23900 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2005–0161; FRL–8299–9] 

RIN 2060–AN76 

Regulation of Fuels and Fuel 

Additives: Renewable Fuel Standard 

Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: Under the Clean Air Act, as 

amended by Section 1501 of the Energy 

Policy Act of 2005, the Environmental 

Protection Agency is required to 

promulgate regulations implementing a 

renewable fuel program. The statute 

specifies the total volume of renewable 

fuel that the regulations must ensure is 

used in gasoline sold in the U.S. each 

year, with the total volume increasing 

over time. In this context, this program 

is expected to reduce dependence on 

foreign sources of petroleum, increase 

domestic sources of energy, and help 

transition to alternatives to petroleum in 

the transportation sector. The increased 

use of renewable fuels such as ethanol 

and biodiesel is also expected to have 

the added effect of providing an 

expanded market for agricultural 

products such as corn and soybeans. 

Based on our analysis, we believe that 

the expanded use of renewable fuels 

will provide reductions in carbon 

dioxide emissions that have been 

implicated in climate change. Also, 

there will be some reductions in air 

toxics emissions such as benzene from 

the transportation sector, while some 

other emissions such as oxides of 

nitrogen are expected to increase. 

This action finalizes regulations 

designed to ensure that refiners, 

blenders, and importers of gasoline will 

use enough renewable fuel each year so 

that the total volume requirements of 

the Energy Policy Act are met. Our rule 

describes the standard that will apply to 

these parties and the renewable fuels 

that qualify for compliance. The 

regulations also establish a trading 

program that will be an integral aspect 

of the overall program, allowing 

renewable fuels to be used where they 

are most economical while providing a 

flexible means for obligated parties to 

comply with the standard. 

DATES: This final rule is effective on 

September 1, 2007. The incorporation 

by reference of certain publications 

listed in the rule is approved by the 

Director of the Federal Register as of 

September 1, 2007. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2005–0161. All 

documents in the docket are listed in 

the www.regulations.gov Web site. 

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

www.regulations.gov or in hard copy at 

the EPA Docket Center, EPA/DC, EPA 

West, Room 3334, 1301 Constitution 

Ave., NW., Washington, DC. This 

Docket Facility is open from 8:30 a.m. 

to 4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744 and the telephone 

number for the EPA Docket Center is 

(202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Julia 

MacAllister, U.S. Environmental 

Protection Agency, National Vehicle 

and Fuel Emissions Laboratory, 2000 

Traverwood, Ann Arbor MI, 48105; 

telephone number (734) 214–4131; fax 

number (734) 214–4816; e-mail address 

macallister.julia@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

Entities potentially affected by this 

action include those involved with the 

production, distribution and sale of 

gasoline motor fuel or renewable fuels 

such as ethanol and biodiesel. Regulated 

categories and entities could include: 

Category NAICS1

codes 

SIC 2

codes Examples of potentially regulated entities 

Industry ........................ 324110 2911 Petroleum Refineries. 

Industry ....................... 325193 2869 Ethyl alcohol manufacturing. 

Industry ........................ 325199 2869 Other basic organic chemical manufacturing. 

Industry ........................ 424690 5169 Chemical and allied products merchant wholesalers. 

Industry ........................ 424710 5171 Petroleum bulk stations and terminals. 

Industry ........................ 424720 5172 Petroleum and petroleum products merchant wholesalers. 

Industry ........................ 454319 5989 Other fuel dealers. 

1 North American Industry Classification System (NAICS). 

2Standard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but provides a guide for 

readers regarding entities likely to be 

regulated by this action. This table lists 

the types of entities that EPA is now 

aware could potentially be affected by 

this action. Other types of entities not 

listed in the table could also be affected. 

To decide whether your organization 

might be affected by this action, you 

should carefully examine today’s notice 

and the existing regulations in 40 CFR 

part 80. If you have any questions 

regarding the applicability of this action 

to a particular entity, consult the 

persons listed in the preceding FOR

FURTHER INFORMATION CONTACT section. 

Table of Contents 

I. Introduction 

A. The Role of Renewable Fuels in the 

Transportation Sector 

B. Requirements in the Energy Policy Act 

C. Development of the RFS Program 

II. Overview of the Program 

A. Impacts of Increased Reliance on 

Renewable Fuels 

1. Renewable Fuel Volume Scenarios 

Analyzed 

2. Emissions 

3. Economic Impacts 

4. Greenhouse Gases and Fossil Fuel 

Consumption 

5. Post 2012 RFS Standards 

B. Program Structure 

1. What Is the RFS Program Standard? 

2. Who Must Meet the Standard? 

3. What Qualifies as a Renewable Fuel? 

4. Equivalence Values of Different 

Renewables Fuels 

5. How Will Compliance Be Determined? 

6. How Will the Trading Program Work? 

7. How Will the Program Be Enforced? 

C. Voluntary Green Labeling Program 

III. Complying With the Renewable Fuel 

Standard 

A. What Is the Standard That Must Be Met? 

1. How Is the Percentage Standard 

Calculated? 

2. What Are the Applicable Standards? 

3. Compliance in 2007 


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4. Renewable Volume Obligations 

B. What Counts as a Renewable Fuel in the 

RFS Program? 

1. What Is a Renewable Fuel That Can Be 

Used for Compliance? 

a. Ethanol Made From a Cellulosic 

Feedstock 

b. Ethanol Made From any Feedstock in 

Facilities Using Waste Material To 

Displace 90 Percent of Normal Fossil 

Fuel Use 

c. Ethanol That Is Made From the NonCellulosic Portions of Animal, Other 

Waste, and Municipal Waste 

d. Foreign Producers of Cellulosic and 

Waste-Derived Ethanol 

2. What Is Biodiesel? 

a. Biodiesel (Mono-Alkyl Esters) 

b. Non-Ester Renewable Diesel 

3. Does Renewable Fuel Include Motor 

Fuel That Is Made From Coprocessing a 

Renewable Feedstock With Fossil Fuels? 

a. Definition of ‘‘Renewable Crudes’’ and 

‘‘Renewable Crude-Based Fuels’’ 

b. How Are Renewable Crude-Based Fuel 

Volumes Measured? 

4. What Are ‘‘Equivalence Values’’ for 

Renewable Fuel? 

a. Authority Under the Act To Establish 

Equivalence Values 

b. Energy Content and Renewable Content 

as the Basis for Equivalence Values 

c. Lifecycle Analyses as the Basis for 

Equivalence Values 

C. What Gasoline Is Used To Calculate the 

Renewable Fuel Obligation and Who Is 

Required To Meet the Obligation? 

1. What Gasoline Is Used To Calculate the 

Volume of Renewable Fuel Required To 

Meet a Party’s Obligation? 

2. Who Is Required To Meet the Renewable 

Fuels Obligation? 

3. What Exemptions Are Available Under 

the RFS Program? 

a. Small Refinery and Small Refiner 

Exemption 

b. General Hardship Exemption 

c. Temporary Hardship Exemption Based 

on Unforeseen Circumstances 

4. What Are the Opt-in and State Waiver 

Provisions Under the RFS Program? 

a. Opt-in Provisions for Noncontiguous 

States and Territories 

b. State Waiver Provisions 

D. How Do Obligated Parties Comply With 

the Standard? 

1. Why Use Renewable Identification 

Numbers? 

a. RINs Serve the Purpose of a Credit 

Trading Program 

b. Alternative Approach To Tracking 

Batches 

2. Generating RINs and Assigning Them to 

Batches 

a. Form of Renewable Identification 

Numbers 

b. Generating RINs 

c. Cases in Which RINS Are Not Generated 

3. Calculating and Reporting Compliance 

a. Using RINs To Meet the Standard 

b. Valid Life of RINs 

c. Cap on RIN Use To Address Rollover 

d. Deficit Carryovers 

4. Provisions for Exporters of Renewable 

Fuel 

5. How Will the Agency Verify 

Compliance? 

E. How Are RINs Distributed and Traded? 

1. Distribution of RINs With Volumes of 

Renewable Fuel 

a. Responsibilities of Renewable Fuel 

Producers and Importers 

b. Responsibilities of Parties That Buy, 

Sell, or Handle Renewable Fuels 

c. Batch Splits and Batch Mergers 

2. Separation of RINs From Volumes of 

Renewable Fuel 

3. Distribution of Separated RINs 

4. Alternative Approaches to RIN 

Distribution 

IV. Registration, Recordkeeping, and 

Reporting Requirements 

A. Introduction 

B. Registration 

1. Who Must Register Under the RFS 

Program? 

2. How Do I Register? 

3. How Do I Know I am Properly Registered 

With EPA? 

4. How are Small Volume Domestic 

Producers of Renewable Fuels Treated 

for Registration Purposes? 

C. Reporting 

1. Who Must Report Under the RFS 

Program? 

2. What Reports Are Required Under the 

RFS Program? 

3. What Are the Specific Reporting Items 

for the Various Types of Parties Required 

To Report? 

4. What are the Reporting Deadlines? 

5. How May I Submit Reports to EPA? 

6. What Does EPA Do With the Reports it 

Receives? 

7. May I Claim Information in Reports as 

CBI and How Will EPA Protect it? 

8. How are Spilled Volumes With 

Associated Lost RINs To Be Handled in 

Reports? 

D. Recordkeeping 

1. What Types of Records Must Be Kept? 

2. What Recordkeeping Requirements are 

Specific to Producers of Cellulosic or 

Waste-Derived Ethanol? 

E. Attest Engagements 

1. What Are the Attest Engagement 

Requirements Under the RFS Program? 

2. Who Is Subject to the Attest Engagement 

Requirements for the RFS Program? 

3. How Are the Attest Engagement 

Requirements in this Final Rule Different 

From Those Proposed? 

V. What Acts Are Prohibited and Who Is 

Liable for Violations? 

VI. Current and Projected Renewable Fuel 

Production and Use 

A. Overview of U.S. Ethanol Industry and 

Future Production/Consumption 

1. Current Ethanol Production 

2. Expected Growth in Ethanol Production 

3. Current Ethanol and MTBE 

Consumption 

4. Expected Growth in Ethanol 

Consumption 

B. Overview of Biodiesel Industry and 

Future Production/Consumption 

1. Characterization of U.S. Biodiesel 

Production/Consumption 

2. Expected Growth in U.S. Biodiesel 

Production/Consumption 

C. Feasibility of the RFS Program Volume 

Obligations 

1. Production Capacity of Ethanol and 

Biodiesel 

2. Technology Available To Produce 

Cellulosic Ethanol 

a. Sugar Platform 

i. Pretreatment 

ii. Dilute acid hydrolysis 

iii. Concentrated acid hydrolysis 

iv. Enzymatic hydrolysis 

b. Syngas Platform 

c. Plasma Technology 

d. Feedstock Optimization 

3. Renewable Fuel Distribution System 

Capability 

VII. Impacts on Cost of Renewable Fuels and 

Gasoline 

A. Renewable Fuel Production and 

Blending Costs 

1. Ethanol Production Costs 

a. Corn Ethanol 

b. Cellulosic Ethanol 

2. Biodiesel Production Costs 

3. Diesel Fuel Costs 

B. Distribution Costs 

1. Ethanol Distribution Costs 

a. Capital Costs To Upgrade Distribution 

System for Increased Ethanol Volume 

b. Ethanol Freight Costs 

2. Biodiesel Distribution Costs 

C. Estimated Costs to Gasoline 

1. Description of Cases Modeled 

a. Base Case (2004) 

b. Reference Case (2012) 

c. Control Cases (2012) 

2. Overview of Cost Analysis Provided by 

the Contractor Refinery Model 

3. Overall Impact on Fuel Cost 

a. Cost Without Ethanol Subsidies 

b. Gasoline Costs Including Ethanol 

Consumption Tax Subsidies 

VIII. What Are the Impacts of Increased 

Ethanol Use on Emissions and Air 

Quality? 

A. Effect of Renewable Fuel Use on 

Emissions 

1. Emissions From Gasoline Fueled Motor 

Vehicles and Equipment 

a. Gasoline Fuel Quality 

b. Emissions From Motor Vehicles 

c. Nonroad Equipment 

2. Diesel Fuel Quality: Biodiesel 

3. Renewable Fuel Production and 

Distribution 

B. Impact on Emission Inventories 

1. Primary Analysis 

2. Sensitivity Analysis 

3. Local and Regional VOC and NOX

Emission Impacts in July 

C. Impact on Air Quality 

1. Impact of Increased Ethanol Use on 

Ozone 

2. Particulate Matter 

IX. Impacts on Fossil Fuel Consumption and 

Related Implications 

A. Impacts on Lifecycle GHG Emissions 

and Fossil Energy Use 

1. Time Frame and Volumes Considered 

2. GREET Model 

a. Renewable Fuel Pathways Considered 

b. Modifications to GREET 

c. Sensitivity Analysis 

3. Displacement Indexes (DI) 

4. Impacts of Increased Renewable Fuel 

Use 

a. Greenhouse Gases and Carbon Dioxide 

b. Fossil Fuel and Petroleum 

B. Implications of Reduced Imports of 

Petroleum Products 


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1These reductions are relative to the Mobile 

Source Air Toxics (MSAT) standards in effect. 

Additional benzene emission reductions will occur 

as a result of the recently finalized MSAT2 

standards (72 FR 8428, February 26, 2007). 

C. Energy Security Implications of 

Increases in Renewable Fuels 

1. Effect of Oil Use on Long-Run Oil Price, 

U.S. Import Costs, and Economic Output 

2. Short-Run Disruption Premium From 

Expected Costs of Sudden Supply 

Disruptions 

3. Costs of Existing U.S. Energy Security 

Policies 

X. Agricultural Sector Economic Impacts 

XI. Public Participation 

XII. Administrative Requirements 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

1. Overview 

2. Background 

4. Summary of Potentially Affected Small 

Entities 

5. Impact of the Regulations on Small 

Entities 

6. Small Refiner Outreach 

7. Reporting, Recordkeeping, and 

Compliance Requirements 

8. Related Federal Rules 

9. Conclusions 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations. 

K. Congressional Review Act 

L. Clean Air Act Section 307(d) 

XIII. Statutory A 

I. Introduction 

Through today’s final rule, we are 

putting in place a compliance and 

enforcement program that implements 

the renewable fuel program, also known 

as the Renewable Fuel Standard (RFS) 

program. This program accomplishes 

the statutory goal of increasing the 

volume of renewable fuels that are 

required to be used in vehicles in the 

U.S. as required in Section 211(o) of the 

Clean Air Act (CAA) enacted as part of 

the Energy Policy Act of 2005 (the 

Energy Act or the Act). This final rule 

resulted from a collaborative effort with 

stakeholders, including refiners, 

renewable fuel producers, and 

distributors, who together helped to 

design a program that is simple, flexible, 

and enforceable. 

As a result of the favorable economics 

of renewable fuels in comparison to 

conventional gasoline and diesel, 

renewable fuel volumes are expected to 

exceed the requirements of the RFS 

program. We have evaluated the impacts 

of a range of renewable fuel volumes as 

high as 10 billion gallons in 2012. This 

represents a significant increase over the 

volume of renewable fuel used in 2004 

which was approximately 3.5 billion 

gallons, and this increase is estimated to 

produce a number of significant effects. 

For instance, we estimate that the 

transition to renewable fuels will reduce 

petroleum consumption by 2.0 to 3.9 

billion gallons or approximately 0.8 to 

1.6 percent of the petroleum that would 

otherwise be used by the transportation 

sector. 

The increased use of renewable fuels 

is also expected to produce reductions 

in some regulated pollutants. Carbon 

monoxide emissions from gasoline 

powered vehicles and equipment will 

be reduced by 0.9 to 2.5 percent and 

emissions of benzene (a mobile source 

air toxic) will be reduced by 1.8 to 4.0 

percent.1 At the same time, other 

emissions may increase. Nationwide, we 

estimate between a 41,000 and 83,000 

ton increase in VOC + NOX emissions. 

However, the effects will vary 

significantly by region with some major 

metropolitan areas experiencing small 

emission benefits, while other areas may 

see an increase in VOC emissions from 

4 to 5 percent and an increase in NOX

emissions from 6 to 7 percent from 

gasoline powered vehicles and 

equipment. 

The use of renewable fuel will 

likewise reduce greenhouse gas 

emissions such as carbon dioxide by 8.0 

to 13.1 million metric tons, about 0.4 to 

0.6 percent of the anticipated 

greenhouse gas emissions from the 

transportation sector in the United 

States in 2012. Greenhouse gas 

emissions contribute to climate change, 

and thus, increased renewable use is an 

important step in addressing this issue. 

Finally, we estimate that increases in 

the use of renewable fuels will increase 

net farm income and the nation’s energy 

security. Net U.S. farm income is 

estimated to increase by between $2.6 

and $5.4 billion through transfers from 

users of gasoline and consumers of 

agricultural products used to produce 

ethanol. However, as feedstocks used in 

the production of renewable fuels 

expand beyond the corn and soybeans 

that are most common today, the 

renewable fuels industry is expected to 

continue to diversify and grow in its 

ability to benefit the nation’s 

environment and economy. 

A. The Role of Renewable Fuels in the 

Transportation Sector 

Renewable fuels have been an 

important part of our nation’s 

transportation fuel supply for many 

years. Following the CAA amendments 

of 1990, the use of renewable fuels, 

particularly ethanol, increased 

dramatically. Several key clean fuel 

programs required by the CAA 

established new market opportunities 

for ethanol. A very successful mobile 

source control strategy, the reformulated 

gasoline (RFG) program, was 

implemented in 1995. This program set 

stringent new controls on the emissions 

performance of gasoline, which were 

designed to significantly reduce 

summertime ozone precursors and year 

round air toxics emissions. The RFG 

program also required that RFG meet an 

oxygen content standard. Several areas 

of the country began blending ethanol 

into gasoline to help meet this new 

standard, such as Chicago and St. Louis. 

Another successful clean fuel strategy 

required certain areas exceeding the 

national ambient air quality standard for 

carbon monoxide to also meet an 

oxygen content standard during the 

winter time to reduce harmful carbon 

monoxide emissions. Many of these 

areas, such as Denver and Phoenix, also 

blended ethanol during the winter 

months to help meet this new standard. 

Today, the role and importance of 

renewable fuels in the transportation 

sector continue to expand. In the past 

several years as crude oil prices have 

soared above the lower levels of the 

1990’s, the relative economics of 

renewable fuel use have improved 

dramatically. In addition, since the vast 

majority of crude oil produced in or 

imported into the U.S. is consumed as 

gasoline or diesel fuel in the U.S., 

concerns about our dependence on 

foreign sources of crude oil have 

renewed interest in renewable 

transportation fuels. The emergence of 

more in-depth understanding of the 

impacts of human activities on climate 

change has also focused attention on the 

various ways that renewable fuels can 

reduce the consumption of fossil fuels. 

The passage of the Energy Policy Act of 

2005 demonstrated a strong 

commitment on the part of U.S. 

policymakers to consider additional 

means of supporting renewable fuels as 

a supplement to petroleum-based fuels 

in the transportation sector. The RFS 

program is one such means. 

The RFS program was debated by the 

U.S. Congress over several years before 

finally being enacted through passage of 

the Energy Policy Act of 2005. The RFS 

program is first and foremost designed 


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to increase the use of renewable fuels in 

motor vehicle fuel consumed in the U.S. 

In this context, it is expected to 

simultaneously reduce dependence on 

foreign sources of petroleum, increase 

domestic sources of energy, and 

diversify our energy portfolio to help 

transition to alternatives to petroleum in 

the transportation sector. Based on our 

analysis, we also believe that the 

expanded use of renewable fuels will 

provide reductions in carbon dioxide 

emissions that contribute to climate 

change and in air toxics emissions such 

as benzene from the transportation 

sector, while other emissions such as 

hydrocarbons and oxides of nitrogen are 

projected to increase. The increased use 

of renewable fuels such as ethanol and 

biodiesel is also expected to have the 

added effect of providing an expanded 

market for agricultural products such as 

corn and soybeans. The expected 

increase in cellulosic ethanol 

production will also expand the market 

opportunities to a wider array of 

feedstocks. 

The requirement for use of a specified 

volume of renewable fuels complements 

other provisions of the Energy Act. In 

particular, the required volume of 

renewable fuel use will offset any 

possible loss in demand for renewable 

fuels occasioned by the Act’s repeal of 

the oxygen content mandate in the RFG 

program while allowing greater 

flexibility in how renewable fuels are 

blended into the nation’s fuel supply. 

The RFS program also creates a specific 

annual level for minimum renewable 

fuel use which increases over time, 

ensuring overall growth in the demand 

and opportunity for renewable fuels. 

Because renewable fuels such as 

ethanol and biodiesel are not new to the 

U.S. transportation sector, the 

expansion of their use is expected to 

follow distribution and blending 

practices already in place. For instance, 

the market already has the necessary 

production and distribution 

mechanisms in place in many areas and 

the ability to expand these mechanisms 

into new markets. Recent spikes in 

ethanol use resulting first from the state 

MTBE bans, and now the virtual 

elimination of MTBE from the 

marketplace, have tested the limits of 

the ethanol distribution system. 

However, future growth is expected to 

move in a more orderly fashion since 

the use of renewable fuels will not be 

geographically constrained and, given 

EIA volume projections, investment 

decisions can follow market forces 

rather than regulatory mandates. In 

addition, the increased production 

volumes of ethanol and the expanded 

penetration of ethanol in new markets 

may create new opportunities for 

blending of E85, a blend of 85 percent 

ethanol and 15 percent gasoline, in the 

long run. The increased availability of 

E85 will mean that more flexible fueled 

vehicles (FFV) can use this fuel. Of the 

approximately 5 million FFVs currently 

in use in the U.S, most are currently 

fueled with conventional gasoline rather 

than E85, in part due to the limited 

availability of E85. 

Given the ever-increasing demand for 

petroleum-based products in the 

transportation sector, the RFS program 

also moves the nation in the direction 

of replacing part of this demand with 

renewable energy. The RFS program 

provides the certainty that at least a 

minimum amount of renewable fuel will 

be used in the U.S., which in turn 

provides some certainty for investment 

in production capacity of renewable 

fuels. However, it should be understood 

that the RFS program is not the only 

factor currently impacting demand for 

ethanol and other renewable fuels. As 

Congress was developing the RFS 

program in the Energy Act, several large 

states were adopting and implementing 

bans on the use of MTBE in gasoline. As 

a result, refiners supplying reformulated 

gasoline (RFG) in those states switched 

to ethanol to satisfy the oxygen content 

mandate for their RFG, causing a large, 

sudden increase in demand for ethanol. 

Even more importantly, with the 

removal of the oxygen content mandate 

for RFG, refiners elected to remove 

essentially all MTBE from the gasoline 

supply in the U.S. during the spring of 

2006. In order to accomplish this 

transition quickly, while still 

maintaining gasoline volume, octane, 

and gasoline air toxics performance 

standards, refiners elected to blend 

ethanol into virtually all reformulated 

gasoline nationwide. This caused a 

second dramatic increase in demand for 

ethanol, which in the near term was met 

by temporarily shifting large volumes of 

ethanol out of conventional gasoline 

and into the RFG areas. 

Perhaps the largest impact on 

renewable fuel demand, however, has 

been the increase in the cost of crude 

oil. In the last few years, both crude oil 

prices and crude oil price forecasts have 

increased dramatically. This has 

resulted in a large economic incentive 

for the use of ethanol and biodiesel. The 

Energy Information Administration 

(EIA) and others are currently projecting 

renewable fuel demand to exceed the 

minimum volumes required under the 

RFS program by a substantial margin. In 

this context, the effect of the RFS 

program is to provide a minimum level 

of demand to support ongoing 

investment in renewable fuel 

production. However, market demand 

for renewable fuels is expected to 

exceed the statutory minimums. We 

believe that the program we are 

finalizing today will operate effectively 

regardless of the level of renewable fuel 

use or market conditions in the energy 

sector. 

B. Requirements in the Energy Policy 

Act 

Section 1501 of the Energy Policy Act 

amended the Clean Air Act and 

provides the statutory basis for the RFS 

program in Section 211(o). It requires 

EPA to establish a program to ensure 

that the pool of gasoline sold in the 

contiguous 48 states contains specific 

volumes of renewable fuel for each 

calendar year starting with 2006. The 

required overall volumes for 2006 

through 2012 are shown in Table I.B–1 

below. 

TABLE I.B–1.— APPLICABLE VOLUMES

OF RENEWABLE FUEL UNDER THE

RFS PROGRAM

Calendar year 

Billion 

gallons 

2006 

2006 .............................................. 4.0 

2007 .............................................. 4.7 

2008 .............................................. 5.4 

2009 .............................................. 6.1 

2010 .............................................. 6.8 

2011 .............................................. 7.4 

2012 .............................................. 7.5 

In order to ensure the use of the total 

renewable fuel volume specified for 

each year, the Agency must set a 

standard for each year representing the 

amount of renewable fuel that each 

refiner, blender, or importer must use, 

expressed as a percentage of gasoline 

sold or introduced into commerce. This 

yearly percentage standard is to be set 

at a level that will ensure that the total 

renewable fuel volumes shown in Table 

I.B–1 will be used based on gasoline 

volume projections provided by the 

Energy Information Administration 

(EIA). The standard for each year must 

be published in the Federal Register by 

November 30 of the previous year. 

Starting with 2013, EPA is required to 

establish the applicable national 

volume, based on the criteria contained 

in the statute, which must require at 

least the same overall percentage of 

renewable fuel use as was required in 

2012. 

The Act defines renewable fuels 

primarily on the basis of the feedstock. 

In general, renewable fuel must be a 

motor vehicle fuel that is produced from 

plant or animal products or wastes, as 

opposed to fossil fuel sources. The Act 


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specifically identifies several types of 

motor vehicle fuels as renewable fuels, 

including cellulosic biomass ethanol, 

waste-derived ethanol, biogas, biodiesel, 

and blending components derived from 

renewable fuel. 

The standard set annually by EPA is 

to be a single percentage applicable to 

refiners, blenders, and importers, as 

appropriate. The percentage standard is 

used by obligated parties to determine a 

volume of renewable fuel that they are 

responsible for introducing into the 

domestic gasoline pool for the given 

year. The percentage standard must be 

adjusted such that it does not apply to 

multiple parties for the same volume of 

gasoline. The standard must also take 

into account the use of renewable fuel 

by small refineries that are exempt from 

the program until 2011. 

Under the Act, the required volumes 

in Table I.B–1 apply to the contiguous 

48 states. However, Alaska and Hawaii 

can opt into the program, in which case 

the pool of gasoline used to calculate 

the standard, and the number of 

regulated parties, would change. In 

addition, other states can request a 

waiver of the RFS program under 

certain conditions, which would affect 

the national quantity of renewable fuel 

required under the program. 

The Act requires the Agency to 

promulgate a credit trading program for 

the RFS program whereby an obligated 

party may generate credits for overcomplying with their annual obligation. 

The obligated party can then use these 

credits to meet their requirements in the 

following year or trade them for use by 

another obligated party. Thus the credit 

trading program allows obligated parties 

to comply in the most cost-effective 

manner by permitting them to generate, 

transfer, and use credits. The trading 

program also permits renewable fuels 

that are not blended into gasoline, such 

as biodiesel, to participate in the RFS 

program. 

The Agency must determine who can 

generate credits, under what conditions 

credits may be traded, how credits may 

be transferred from one party to another, 

and the appropriate value of credits for 

different types of renewable fuel. If a 

party is not able to generate or purchase 

sufficient credits to meet their annual 

obligation, they are allowed to carry 

over the deficit to the next annual 

compliance period, but must achieve 

full compliance in that following year. 

C. Development of the RFS Program 

Section 1501 of the Energy Act 

prescribed the RFS program, including 

the required total volumes, the timing of 

the obligation, the parties who are 

obligated to comply, the definition of 

renewable fuel, and the general 

framework for a credit trading program. 

Various aspects of the program require 

additional development by the Agency 

beyond the specifications in the Act. 

The Agency must develop regulations to 

ensure the successful implementation of 

the RFS program, based on the 

framework spelled out in the statute. 

Under the RFS program the trading 

provisions comprise an integral element 

of compliance. Many obligated parties 

do not have access to renewable fuels or 

the ability to blend them, and so must 

use credits to comply. The RFS trading 

program is also unique in that the 

parties liable for meeting the standard 

(refiners, importers, and blenders of 

gasoline) are not generally the parties 

who make the renewable fuels or blend 

them into gasoline. This creates the 

need for trading mechanisms that 

ensure that the means to demonstrate 

compliance will be readily available for 

use by obligated parties. 

The first step we took in developing 

the proposed program was to seek input 

and recommendations from the affected 

stakeholders. There were initially a 

wide range of thoughts and views on 

how to design the program. However, 

there was broad consensus that the 

program should satisfy a number of 

guiding principles, including, for 

example, that the compliance and 

trading program should provide 

certainty to the marketplace and 

minimize cost to the consumers; that the 

program should preserve existing 

business practices for the production, 

distribution, and use of both 

conventional and renewable fuels; that 

the program should be designed to 

accommodate all qualifying renewable 

fuels; that all renewable volumes 

produced are made available to 

obligated parties for compliance; and 

that the Agency should have the ability 

to easily verify compliance to ensure 

that the volume obligations are in fact 

met. These guiding principles and the 

comments we received on our Notice of 

Proposed Rulemaking (NPRM) helped to 

move us toward the program in today’s 

final rule. 

We published a Notice of Proposed 

Rulemaking on September 22, 2006 (71 

FR 55552) which described our 

proposed approach to compliance and 

the trading program, as well as 

preliminary analyses of the 

environmental and economic impacts of 

increased use of renewable fuels. The 

program finalized today largely mirrors 

the proposed program, with some 

revisions reflecting continued input 

from stakeholders during the formal 

comment period. 

II. Overview of the Program 

Today’s action establishes the final 

requirements for the RFS program, as 

well as our assessment of the 

environmental and economic impacts of 

the nation’s transition to greater use of 

renewable fuels. This section provides 

an overview of our program and 

renewable fuel impacts assessment. 

Sections III through V provide the 

details of the structure of the program, 

while Sections VI through X describe 

our assessment of the impacts on 

emissions of regulated pollutants and 

greenhouse gases, air quality, fossil fuel 

use, energy security, economic impacts 

in the agricultural sector, and cost from 

the expanded use of renewable fuels. 

A. Impacts of Increased Reliance on 

Renewable Fuels 

In a typical major rulemaking, EPA 

would conduct a full assessment of the 

economic and environmental impacts of 

the specific rule that it is promulgating. 

However, as discussed in Section I.A., 

the replacement of MTBE with ethanol 

and the extremely favorable economics 

for renewable fuels brought on by the 

rise in crude oil prices are causing 

renewable fuel use to far exceed the RFS 

requirements. Given these 

circumstances, it is important to assess 

the impacts of this larger increase in 

renewable use and the related changes 

occurring to gasoline. For this reason we 

have carried out an assessment of the 

economic and environmental impacts of 

the broader changes in fuel quality 

resulting from our nation’s transition to 

greater utilization of renewable fuels, as 

opposed to an assessment that is limited 

to the RFS program itself. 

To carry out our analyses, we elected 

to use 2004 as the baseline from which 

to compare the impacts of expanded 

renewable use. We chose 2004 as a 

baseline primarily due to the fact that 

all the necessary refinery production 

data, renewable fuel production data, 

and fuel quality data were already in 

hand at the time we needed to begin the 

analysis. We did not use 2005 as a 

baseline year because 2005 may not be 

an appropriate year for comparison due 

to the extraordinary impacts of 

hurricanes Katrina and Rita on gasoline 

production and use. To assess the 

impacts of anticipated increases in 

renewable fuels, we elected to look at 

what they would be in 2012, the year 

the statutorily-mandated renewable fuel 

volumes will be fully phased in. By 

conducting the analysis in this manner, 

the impacts include not just the impact 

of expanded renewable fuel use by 

itself, but also the corresponding 

decrease in the use of MTBE, and the 


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2 $48/barrel from Annual Energy Outlook 2006, 

Energy Information Administration, Department of 

Energy. 

3Subsequent to the analysis for this final rule, 

EIA has released its 2007 AEO forecasts for ethanol 

use, which increase the projection to 11.2 billion 

gallons by 2012. 

potential for oxygenates to be removed 

from RFG due to the absence of the RFG 

oxygenate mandate. Since these three 

changes are all inextricably linked and 

are occurring simultaneously in the 

marketplace, evaluating the impacts in 

this manner is both necessary and 

appropriate. 

We evaluated the impacts of 

expanded renewable fuel use and the 

corresponding changes to the fuel 

supply on fuel costs, consumption of 

fossil fuels, and some of the economic 

impacts on the agricultural sector and 

energy security. We also evaluated the 

impacts on emissions, including 

greenhouse gas emissions that 

contribute to climate change, and the 

corresponding impacts on nationwide 

and regional air quality. Our analyses 

are summarized in this section. 

1. Renewable Fuel Volume Scenarios 

Analyzed 

As shown in Table I.B–1, the Act 

stipulates that the nationwide volumes 

of renewable fuel required under the 

RFS program must be at least 4.0 billion 

gallons in 2006 and increase to 7.5 

billion gallons in 2012. However, we 

expect that the volume of renewable 

fuel will actually exceed the required 

volumes by a significant margin. Based 

on economic modeling in 2006, EIA 

projected renewable fuel demand in 

2012 of 9.6 billion gallons for ethanol, 

and approximately 300 million gallons 

for biodiesel using crude oil prices 

forecast at $48 per barrel.2 Therefore, in 

assessing the impacts of expanded use 

of renewable fuels, we evaluated two 

comparative scenarios, one representing 

the statutorily required minimum, and 

another reflecting the higher levels 

projected by EIA. Although the actual 

renewable fuel volumes produced in 

2012 may differ from both the required 

and projected volumes, we believe that 

these two volume scenarios together 

represent a reasonable range for analysis 

purposes.3

The Act also stipulates that at least 

250 million gallons out of the total 

volume required in 2013 and beyond 

must meet the definition specified for 

cellulosic biomass ethanol. As described 

in Section VI, there are a number of 

companies already making plans to 

produce ethanol from cellulosic 

feedstocks and/or waste-derived energy 

sources that could potentially meet the 

definition of cellulosic biomass ethanol. 

Accordingly, we anticipate a ramp-up in 

production of cellulosic biomass 

ethanol production in the coming years, 

and for analysis purposes we have 

assumed that 250 million gallons of 

cellulosic biomass ethanol will be used 

in 2012. 

As discussed in Section VI, we chose 

2004 to represent current baseline 

conditions. However, a direct 

comparison of the fuel quality impacts 

on emissions and air quality that are 

expected to occur once the RFS program 

is fully phased in required that changes 

in overall fuel volume, fleet 

characterization, and other factors be 

constant. Therefore, we created a 2012 

reference case from the 2004 base case 

for use in the emissions and air quality 

analysis that maintained current fuel 

quality parameters while incorporating 

forecasted increases in vehicle miles 

traveled and changes in fleet 

demographics. The 2012 fuel reference 

case was developed by growing out the 

2004 renewable fuel baseline according 

to EIA’s forecasted energy growth rates 

between 2004 and 2012. 

For the analyses, we created two 2012 

scenarios representing expanded 

renewable fuel production. The ‘‘RFS 

Case’’ represents volume levels 

designed to exactly meet the 

requirements of the RFS program, and 

includes the effects of higher credit 

values for cellulosic ethanol and 

biodiesel. Since higher credit values 

mean that one gallon of renewable fuel 

counts as more than one gallon for 

compliance purposes, less than 7.5 

billion gallons of renewable fuel is 

needed to meet the 7.5 billion gallon 

statutory requirement, but credits 

equivalent to 7.5 billion gallons of 

renewable fuel would still be available 

for compliance purposes. The ‘‘EIA 

Case’’ represents volume levels based on 

EIA projections. A summary of the 

assumed renewable fuel volumes for the 

scenarios we evaluated is shown in 

Table II.A.1–1. Details of the 

calculations used to determine these 

volumes are given in Chapter 2 of the 

Regulatory Impact Analysis (RIA) in the 

docket for this rulemaking. 

TABLE II.A.1–1.—RENEWABLE FUEL VOLUME SCENARIOS (BILLION GALLONS) 

2004 

base case 

2012 

Reference 

case RFS case EIA case 

Corn-ethanol ............................................................................................................................ 3 .548 3 .947 6 .421 9 .388 

Cellulosic ethanol ..................................................................................................................... 0 0 0 .25 0 .25 

Biodiesel .................................................................................................................................. 0 .025 0 .030 0 .303 0 .303 

Total volume ..................................................................................................................... 3 .573 3 .977 6 .974 9 .941 

2. Emissions 

We evaluated the impacts of increased 

use of ethanol and biodiesel on 

emissions and air quality in the U.S. 

relative to the reference case. We 

estimated that nationwide VOC 

emissions in 2012 from gasoline 

vehicles and equipment will increase by 

about 0.3% in the RFS Case and about 

0.7% in the EIA Case. For NOX, we 

estimated that nationwide annual 

emissions in 2012 will increase about 

0.9% for the RFS Case and 1.6% for the 

EIA Case. These increases are equivalent 

to an additional 18,000 to 43,000 tons of 

VOC per year, and an additional 23,000 

to 40,000 tons of NOX per year. 

We also estimated the change in 

emissions in those areas which are 

projected to experience a significant 

change in ethanol use; i.e., where the 

market share of ethanol blends was 

projected to change by 50 percent or 

more. We focused on July emissions 

since these are most relevant to ozone 

formation and modeled 2015 because 

our ozone model is based upon a 2015 

emissions inventory (though we would 

expect similar results in 2012). Finally, 

we developed separate estimates for 

RFG areas, low RVP areas (i.e., RVP 

standards less than 9.0 RVP), and 

conventional gasoline areas with a 

summer 9.0 RVP standard. For areas 

with a significant change in ethanol use, 


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4Advanced emission controls include closecoupled, high-density catalysts and their associated 

electronic control systems for light-duty vehicles, 

and NOX adsorbers and PM traps for heavy-duty 

engines. 

compared to the reference case, VOC 

emissions in RFG areas increased by up 

to 2.3%, while NOX emissions increased 

by up to 1.6%. In low RVP areas, VOC 

emissions increased by up to 4.6%, 

while NOX emissions increased by up to 

6.2%. In 9.0 RVP areas, VOC emissions 

increased by up to 4.6%, while NOX

emissions increased by up to 7.3%. 

Unlike VOC and NOX, emissions of 

CO and benzene from gasoline vehicles 

and equipment were estimated to 

decrease in 2012 when the use of 

renewable fuels increased. Reductions 

in emissions of CO varied from 0.9% 

percent to as high as 2.5% percent for 

the nation as a whole, depending on the 

renewable fuel volume scenario. 

Similarly, benzene emissions from 

gasoline vehicles and equipment were 

estimated to be reduced from 1.8% to 

4.0% percent. 

We do not have sufficient data to 

predict the effect of ethanol use on 

levels of either directly emitted 

particulate matter (PM) or secondarily 

formed PM. The increased NOX

emissions are expected to lead to 

increases in secondary nitrate PM, but at 

the same time reduced aromatics 

resulting from ethanol blending are 

likely to lead to a decrease in secondary 

organic PM, as discussed in Section 

VIII.C. In addition, biodiesel use is 

expected to result in some reduction in 

direct PM emissions, though small in 

magnitude due to the relatively small 

volumes. 

The emission impact estimates 

described above are based on the best 

available data and models. However, it 

must be highlighted that most of the fuel 

effect estimates are based on very 

limited or old data which may no longer 

be reliable in estimating the emission 

impacts on vehicles in the 2012 fleet 

with advanced emission controls.4 As 

such, these emission estimates should 

be viewed as preliminary. EPA hopes to 

conduct significant new testing in order 

to better estimate the impact of fuel 

changes on emissions from both 

highway vehicles and nonroad 

equipment, including those fuel changes 

brought about by the use of renewable 

fuels. We hope to be able to incorporate 

the data from such additional testing 

into the analyses for other studies 

required by the Energy Act, and into a 

subsequent rule to set the RFS program 

standard for 2013 and later. 

We used the Ozone Response Surface 

Model (RSM) to estimate the impacts of 

the increased use of ethanol on ozone 

levels for both the RFS Case and the EIA 

Case. The ozone RSM approximates the 

effect of VOC and NOX emissions in a 

37-state eastern area of the U.S. Using 

this model, we projected that the 

changes in VOC and NOX emissions 

could produce a very small increase in 

ambient ozone levels. On average, 

population-weighted ozone design value 

concentrations increased by about 0.05 

ppb, which represents 0.06 percent of 

the standard. Even for areas expected to 

experience a significant increase in 

ethanol use, population-weighted ozone 

design value concentrations increased 

by only 0.15 to 0.18 ppb, about 0.2 

percent of the standard. These ozone 

impacts do not consider the reductions 

in CO emissions mentioned above, or 

the change in the types of compounds 

comprising VOC emissions. 

Directionally, both of these factors may 

mitigate these ozone increases. 

We investigated several other issues 

related to emissions and air quality that 

could affect our estimates of the impacts 

of increased use of renewable fuels. 

These are discussed in Section VIII and 

in greater detail in the RIA. For 

instance, our current models assume 

that recent model year vehicles are 

insensitive to many fuel changes. 

However, a limited amount of new test 

data suggest that newer vehicles may be 

just as sensitive as older model year 

vehicles. Our sensitivity analysis 

suggests that if this is the case, VOC 

emissions could decrease by as much as 

0.3%, instead of increasing by up to 

0.7%. NOX emissions could increase by 

up to 4.2%, up from a 1.6% increase. 

We also evaluated the emissions from 

the production of both ethanol and 

biodiesel fuel and determined that they 

will also increase with increased use of 

these fuels. Nationwide, emissions 

related to the production and 

distribution of ethanol and biodiesel 

fuel are projected to be of the same 

order of magnitude as the emission 

impacts related to the use of these fuels 

in vehicles. 

Finally, a lack of emission data and 

atmospheric modeling tools prevented 

us from making specific projections of 

the impact of renewable fuels on 

ambient PM levels. As mentioned, 

however, ethanol use may affect 

ambient PM levels due to the increase 

in NOX emissions and the reduction in 

the aromatic content of gasoline, which 

should reduce aromatic VOC emissions. 

All of these issues will be the subject of 

further study and analysis in the future. 

3. Economic Impacts 

In Section VII of this preamble, we 

estimate the cost of producing the extra 

volumes of renewable fuel anticipated 

through 2012. For corn ethanol, we 

estimate the per gallon cost of ethanol 

to range from $1.26 per gallon in 2012 

(2004 dollars) in the RFS Case to $1.32 

per gallon in the EIA Case. These costs 

take into account the cost of the 

feedstock (corn), plant equipment and 

operation and the value of any coproducts (distiller’s dried grain and 

solubles, for example). For biodiesel, we 

estimate the per gallon cost to be 

between $1.89 and $2.06 per gallon if 

produced using soy bean oil, and less if 

using yellow grease ($1.11 to $1.56 per 

gallon) or other relatively low cost or 

no-cost feedstocks. The price paid for 

ethanol, however, is reduced by the 

$0.51 per gallon federal tax subsidy as 

well as any state subsidies that might 

apply. Similarly the price paid for 

biodiesel is reduced due to the $1.00 per 

gallon federal tax subsidy biodiesel 

produced from soy bean oil and $0.50 

per gallon tax subsidy for biodiesel 

produced from yellow grease. We also 

note that these costs represent the 

production cost of the fuel and not the 

market price. In recent years, the prices 

of ethanol and biodiesel have tended to 

track the prices of gasoline and diesel 

fuel, in some cases even exceeding those 

prices. 

These renewable fuels are then 

blended in gasoline and diesel fuel. 

While biodiesel is typically just blended 

with typical petroleum diesel, 

additional efforts are sometimes 

necessary and/or economically 

advantageous at the refiner level when 

adding ethanol to gasoline. For example, 

ethanol’s high octane reduces the need 

for other octane enhancements by the 

refiner, whereas offsetting the volatility 

increase caused by ethanol may require 

removal of other highly volatile 

components. Section VII examines these 

fuel cost impacts and concludes that the 

net cost to society in 2012 in 

comparison to the reference case will 

range from an estimate of 0.5 cent to 1.0 

cent per gallon of gasoline due to the 

increased use of renewable fuels and 

their displacement of MTBE. The 

resulting total nationwide costs in 2012 

are $823 million per year for the RFS 

case and $1,739 million per year for the 

EIA case. This total excludes the effects 

of the 51 cent/gal federal excise tax 

credit as well as state tax subsidies. 

Our estimates of fuel impacts do not 

consider other societal benefits. For 

example, the displacement of 

petroleum-based fuel (largely imported) 

by renewable fuel (largely produced in 

the United States), should reduce our 

use of imported oil and fuel. We 

estimate that 95 percent of the lifecycle 

petroleum reductions resulting from the 

use of renewable fuel will be met 


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through reductions in net petroleum 

imports. In Section IX of this preamble 

we estimate the value of the decrease in 

imported petroleum at about $2.6 

billion in 2012 for the RFS Case and 

$5.1 billion for the EIA Case, in 

comparison to our 2012 reference case. 

Total petroleum import expenditures in 

2012 are projected to be about $698 

billion. 

Furthermore, the above estimate on 

reduced petroleum import expenditures 

only partly assess the economic 

impacts. One of the effects of increased 

use of renewable fuel is that it 

diversifies the energy sources used in 

making transportation fuel. To the 

extent that diverse sources of fuel 

energy reduce the dependence on any 

one source, the risks, both financial as 

well as strategic, of a potential 

disruption in supply reflected in the 

price volatility of a particular energy 

source are reduced. As indicated in the 

proposal, EPA has worked with 

researchers at Oakridge National 

Laboratory to update a study they 

previously published and which has 

been used or cited in several 

government actions impacting oil 

consumption. A draft report is being 

made available in the docket at this time 

for further consideration. This analysis 

only looks at the impact of reduced 

petroleum imports on energy security. 

Other energy security issues could arise 

with the wider use of biofuels. For 

example, ethanol’s production and costs 

are determined by the availability of 

corn as a feedstock. Corn production, in 

turn, is weather-dependent. Also, the 

use of biofuels may increase the use of 

natural gas. A full integrated analysis of 

the energy security implications of the 

wider use of biofuels has yet to be 

undertaken. 

While increased use of renewable fuel 

will reduce expenditures on imported 

oil, it will also increase expenditures on 

renewable fuels and in-turn, on the 

sources of those renewable fuels. The 

RFS program attempts to spur the 

increased use of renewable 

transportation fuels made principally 

from agricultural crops produced in the 

U.S. As a result, it is important to 

analyze the consequences of the 

transition to greater renewable fuel use 

in the U.S. agricultural sector. To 

perform this analysis, EPA selected the 

Forest and Agricultural Sector 

Optimization Model (FASOM) 

developed by Professor Bruce McCarl of 

Texas A&M University and others over 

the past thirty years. FASOM is a 

dynamic, nonlinear programming model 

of the agriculture and forestry sectors of 

the U.S. (For this analysis, we focused 

on the agriculture portion of the model.) 

Due to the greater demand for corn as 

a feedstock for ethanol production, corn 

prices are estimated to increase in 2012 

by 18 cents per bushel for the RFS Case 

and 39 cents per bushel of corn for the 

EIA Case from $2.32 (in 2004 dollars) in 

the Reference Case. Although soybean 

prices are expected to rise slightly, the 

increased cost is likely due to higher 

input costs, such as land prices. We 

estimate a price increase of 18 cents 

(RFS Case) to 21 cents (EIA Case) per 

bushel of soybeans from a Reference 

Case price of $5.26 per bushel. These 

higher commodity prices are predicted 

to also result in higher U.S. farm 

income. Our analysis predicts that farm 

income will increase by $2.6 billion 

annually by 2012 for the RFS Case and 

$5.4 billion for the EIA Case, roughly a 

5 to 10 percent increase. 

Due to higher corn prices, U.S. 

exports of corn are estimated to decrease 

by $573 million in the RFS Case and by 

$1.29 billion in the EIA Case in 2012. 

With higher commodity prices, we 

would expect some upward pressure on 

food costs as the higher cost of corn and 

soybeans is passed along to consumers. 

We estimate a relatively modest increase 

in annual household food costs 

associated with the higher price 

commanded by corn and soybeans. For 

the RFS Case, annual per capita 

wholesale food cost are estimated to 

increase by approximately $7, while the 

higher renewable fuel volumes 

anticipated by the EIA Case will result 

in a $12 annual increase in the per 

capita wholesale food cost. This equates 

to roughly a $2.1 to $3.6 billion increase 

in nationwide food costs in 2012. 

4. Greenhouse Gases and Fossil Fuel 

Consumption 

There has been considerable interest 

in the impacts of fuel programs on 

greenhouse gases implicated in climate 

change and on fossil fuel consumption 

due largely to concerns about 

dependence on foreign sources of 

petroleum. Therefore, in this 

rulemaking we have undertaken an 

analysis of the greenhouse gas and fossil 

fuel consumption impacts of a transition 

to greater renewable fuel use. This is the 

first analysis of its kind in a high profile 

rule, and as such it may guide future 

work in this area. 

As a result of the transition to greater 

renewable fuel use, some petroleumbased gasoline and diesel will be 

directly replaced by renewable fuels. 

Therefore, consumption of petroleumbased fuels will be lower than it would 

be if no renewable fuels were used in 

transportation vehicles. However, a true 

measure of the impact of greater use of 

renewable fuels on petroleum use, and 

indeed on the use of all fossil fuels, 

accounts not only for the direct use and 

combustion of the finished fuel in a 

vehicle or engine, but also includes the 

petroleum use associated with 

production and transportation of that 

fuel. For instance, fossil fuels are used 

in producing and transporting 

renewable feedstocks such as plants or 

animal byproducts, in converting the 

renewable feedstocks into renewable 

fuel, and in transporting and blending 

the renewable fuels for consumption as 

motor vehicle fuel. Likewise, fossil fuels 

are used in the production and 

transportation of petroleum and its 

finished products. In order to estimate 

the true impacts of increases in 

renewable fuel use on fossil fuel use, we 

must take these steps into account. Such 

analyses are termed lifecycle analyses. 

There is also no consensus on the 

most appropriate approach for 

conducting such lifecycle analyses. We 

have chosen to base our lifecycle 

analysis on Argonne National 

Laboratory’s GREET model for the 

reasons described in Section IX. 

However, there are other lifecycle 

models in use. The choice of model 

inputs and assumptions all have a 

bearing on the results of lifecycle 

analyses, and many of these 

assumptions remain the subject of 

debate among researchers. 

With these caveats, we compared the 

lifecycle impacts of renewable fuels to 

the petroleum-based gasoline and diesel 

fuels that they replace. This analysis 

allowed us to estimate not only the 

overall impacts of renewable fuel use on 

petroleum use, but also on emissions of 

greenhouse gases such as carbon 

dioxide from all fossil fuels. In 

comparison to the reference case, we 

estimate that the increased use of 

renewable fuels in the RFS and EIA 

cases will reduce transportation sector 

petroleum consumption by about 0.8 

and 1.6 percent, respectively, in the 

transportation sector in 2012. This is 

equivalent to 2.0–3.9 billion gallons of 

petroleum in 2012. We also estimated 

that greenhouse gases from the 

transportation sector will be reduced by 

about 0.4 and 0.6 percent for the RFS 

and EIA cases, respectively, equivalent 

to about 8–13 million metric tons. These 

reductions are projected to continue to 

increase beyond 2012 since crude oil 

prices have been projected by EIA to 

continue to be high relative to the prices 

of the 1990’s, and as a result there is 

expected to be an economic advantage 

to using renewable fuels beyond 2012. 

These greenhouse gas emission 

reductions are also highly dependent on 

the expectation that the majority of the 

future ethanol use will be produced 


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5Cellulosic ethanol is estimated to provide a 

comparable petroleum displacement as corn 

derived ethanol on a per gallon basis, though the 

impacts on total energy and greenhouse gas 

emissions differ. 

6While the RFS program is specific to renewable 

fuels, the president’s goal of 35 billion gallons by 

2017 would include not only renewable fuels, but 

also other types of alternatives fuels. 

from corn. If advances in the technology 

for converting cellulosic feedstocks into 

ethanol allow cellulosic ethanol use to 

exceed the levels assumed in our 

analysis, then even greater greenhouse 

gas reductions may result.5

5. Post 2012 RFS Standards 

The Energy Policy Act of 2005, in 

addition to setting the standards to be 

adopted through 2012, requires EPA, in 

coordination with the Departments of 

Agriculture and Energy, to determine 

the applicable volume for the renewable 

fuel standard for the year 2013 and 

subsequent calendar years. This 

determination is to be based on a review 

of the program’s implementation in 

2006 through 2012 as well as review of 

the impact of renewable fuels on the 

environment, air quality, energy 

security, job creation, rural economic 

development and the expected annual 

rate of renewable fuel production, 

including production of cellulosic 

ethanol. 

In today’s final rulemaking, we do not 

suggest any specific renewable fuel 

volumes for 2013 and beyond that may 

be appropriate under the statutory 

criteria. However, we would note that 

the President, in his State of the Union 

address this January, set specific goals 

reducing the amount of gasoline usage 

in the United States by 20 percent in the 

next 10 years. This would be 

accomplished by reforming and 

modernizing fuel economy standards for 

cars and setting mandatory fuels 

standard equivalent to requiring use of 

35 billion gallons of renewable and 

alternative 6 fuels in 2017. Therefore, 

given the necessity to address the post2013 period under the Energy Act and 

the prospect of continued attention by 

the Administration and Congress to this 

issue, EPA will continue to devote 

attention to the issue of renewable and 

alternative fuel volumes in the post2013 period. 

From a program structure perspective, 

we believe that what we are putting in 

place today will remain useful as part of 

a 2013 and later program. For example, 

EPA considers that the identification of 

renewable fuel via a Renewable 

Identification Number (RIN), the 

determination of liable parties, the 

averaging, banking and trading system 

and the recordkeeping and reporting 

system would all be elements of a post2013 program. Depending on the 

structure of any final legislation 

approved by Congress and signed into 

law, such elements could also be 

incorporated into an expanded 

renewable and alternative fuels 

program. 

B. Program Structure 

The RFS program being finalized 

today requires refiners, importers, and 

blenders (other than oxygenate 

blenders) to show that a required 

volume of renewable fuel is used in 

gasoline. The required volume is 

determined by multiplying their annual 

gasoline production by a percentage 

standard specified by EPA. Compliance 

is demonstrated through the acquisition 

of unique Renewable Identification 

Numbers (RINs) assigned by the 

producer or importer to every batch of 

renewable fuel produced or imported. 

The RIN shows that a certain volume of 

renewable fuel was produced or 

imported. Each year, the refiners, 

blenders and importers obligated to 

meet the renewable volume requirement 

(referred to as ‘‘obligated parties’’) must 

acquire sufficient RINs to demonstrate 

compliance with their volume 

obligation. RINs can be traded, thereby 

functioning as the credits envisioned in 

the Act. A system of recordkeeping and 

electronic reporting for all parties that 

have RINs ensures the integrity of the 

RIN pool. This RIN-based system will 

both meet the requirements of the Act 

and provide several other important 

advantages: 

• Renewable fuel production volumes 

can be easily verified. 

• RIN trading can occur in real time 

as soon as the renewable fuel is 

produced rather than waiting to the end 

of the year when an obligated party 

would determine if it had exceeded the 

standard. 

• Renewable fuel can continue to be 

produced, distributed, and blended in 

those markets where it is most 

economical to do so. 

• Instances of double-counting of 

renewable fuel claimed for compliance 

purposes can be identified based on 

electronically reported data. 

Our RIN-based trading program is an 

essential component of the RFS 

program, ensuring that every obligated 

party can comply with the standard 

while providing the flexibility for each 

obligated party to use renewable fuel in 

the most economical ways possible. 

1. What Is the RFS Program Standard? 

EPA is required to convert the 

aggregate national volumes of renewable 

fuel specified in the Act into 

corresponding renewable fuel standards 

expressed as a percent of gasoline 

production or importation. The 

renewable volume obligation that will 

apply to an individual obligated party 

will then be determined based on this 

percentage and the total gasoline 

production or import volume in a 

calendar year, January 1 through 

December 31. EPA will publish the 

percentage standard in the Federal 

Register each November for the 

following year based on the most recent 

EIA gasoline demand projections. 

However, for compliance in 2007 we are 

publishing the percentage standard in 

today’s action. The standard for 2007 is 

4.02 percent. Section III.A describes the 

calculation of the standard. 

2. Who Must Meet the Standard? 

Under our program, any party that 

produces or imports gasoline for 

consumption in the U.S., including 

refiners, importers, and blenders (other 

than oxygenate blenders), will be 

subject to a renewable volume 

obligation that is based on the 

renewable fuel standard. These 

obligated parties will determine the 

level of their obligation by multiplying 

the percentage standard by their annual 

volume of gasoline production or 

importation. The result will be the 

renewable fuel volume which each 

party must ensure is blended into 

gasoline consumed in the U.S., with 

credit for certain other renewable fuels 

that are not blended into gasoline. 

For 2007, we are requiring that the 

renewable fuel volume obligation be 

determined by multiplying the 

percentage standard by the volume of 

gasoline produced or imported 

prospectively from September 1, 2007 

until December 31, 2007. While the 

standard will not apply to all of 2007 

gasoline production, we are 

nevertheless confident that the total 

volume of renewable fuel used in all of 

2007 will still exceed the volume 

specified in the Act due to expectations 

that the demand for renewable fuel will 

exceed the RFS requirements. 

In determining their annual gasoline 

production volume, obligated parties 

must include all of the finished gasoline 

which they produced or imported for 

use in the contiguous 48 states, and 

must also include reformulated 

blendstock for oxygenate blending 

(RBOB), and conventional blendstock 

for oxygenate blending (CBOB). For 

refiners and importers this includes 

unfinished gasoline produced or 

imported that will become gasoline 

upon addition of an oxygenate 

downstream of the refiner. Other 

producers of gasoline, such as blenders, 


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will count as their gasoline production 

only the volumes of blendstocks which 

become gasoline upon their addition to 

finished gasoline, unfinished gasoline, 

or other blendstocks. Renewable fuels 

blended into gasoline by any party will 

not be counted as gasoline for the 

purposes of calculating the annual 

gasoline production volume. 

Small refiners and small refineries are 

exempt from meeting the renewable fuel 

requirements through 2010. All gasoline 

producers located in Alaska, Hawaii, 

and noncontiguous U.S. territories and 

parties who import gasoline into these 

areas will be exempt indefinitely. 

However, if Alaska, Hawaii or a 

noncontiguous territory opts into the 

RFS program, all of the refiners (except 

for exempt small refiners and 

refineries), importers, and blenders 

located in the state or territory will be 

subject to the renewable fuel standard. 

Section III.A provides more details on 

the standard that must be met, while 

Section III.C describes the parties that 

are obligated to meet the standard. 

3. What Qualifies as a Renewable Fuel? 

We have designed the program to 

cover the range of renewable fuels 

produced today as well as any that 

might be produced in the future, so long 

as they meet the Act’s definition of 

renewable fuel and have been registered 

and approved for use in motor vehicles. 

In this manner, we believe that the 

program provides the greatest possible 

encouragement for the development, 

production, and use of renewable fuels 

to reduce our dependence on petroleum 

as well as to reduce the carbon dioxide 

emissions that contribute to climate 

change. In general, renewable fuels must 

be produced from plant or animal 

products or wastes, as opposed to fossil 

fuel sources. Valid renewable fuels 

include ethanol made from starch seeds, 

sugar, or cellulosic materials, biodiesel 

(mono-alkyl esters), non-ester renewable 

diesel, and a variety of other products. 

Both renewable fuels blended into 

conventional gasoline or diesel and 

those used in their neat (unblended) 

form as motor vehicle fuel will qualify. 

Section III.B provides more details on 

the renewable fuels that will be allowed 

to be used for compliance with the 

standard under our program. 

4. Equivalence Values of Different 

Renewables Fuels 

One question that we faced in 

developing the program was what value 

to place on different renewable fuels 

and on what basis should that value be 

determined. The Act specifies that each 

gallon of cellulosic biomass ethanol and 

waste-derived ethanol be treated as if it 

were 2.5 gallons of renewable fuel for 

compliance purposes, but does not 

specify the values for other renewable 

fuels. Although in the NPRM we 

considered a range of options including 

straight volume, energy content, and 

requested comment on the merit and 

basis for setting ‘‘Equivalence Values’’ 

on several metrics including lifecycle 

energy or greenhouse gas emissions, for 

this final rule we are requiring that the 

‘‘Equivalence Values’’ for the different 

renewable fuels be based on their energy 

content in comparison to the energy 

content of ethanol, and adjusted as 

necessary for their renewable content. 

The result is an Equivalence Value for 

corn ethanol of 1.0, for biobutanol of 

1.3, for biodiesel (mono alkyl ester) of 

1.5, for non-ester renewable diesel of 

1.7, and for cellulosic ethanol and 

waste-derived ethanol of 2.5. The 

proposed methodology can be used to 

determine the appropriate Equivalence 

Value for any other potential renewable 

fuel as well. Section III.B.4 provides 

details of the determination of 

Equivalence Values. 

5. How Will Compliance Be 

Determined? 

Under our program, every gallon of 

renewable fuel produced or imported 

into the U.S. must be assigned a unique 

RIN. A block of RINs would be assigned 

to any batch of renewable fuel that is 

valid for compliance purposes under the 

RFS program. These RINs must be 

transferred with renewable fuel as 

ownership of a volume of renewable 

fuel is initially transferred through the 

distribution system. Once the renewable 

fuel is obtained by an obligated party or 

actually blended into a motor vehicle 

fuel, the RIN can be separated from the 

batch of renewable fuel and then either 

used for compliance purposes, held, or 

traded. 

RINs represent proof of production 

which is then taken as proof of 

consumption as well, since all but a 

trivial quantity of renewable fuel 

produced or imported will be either 

consumed as fuel or exported. For 

instance, ethanol produced for use as 

motor vehicle fuel is denatured 

specifically so that it can only be used 

as fuel. Similarly, biodiesel is produced 

only for use as fuel and has no other 

significant uses. An obligated party 

demonstrates compliance with the 

renewable fuel standard by 

accumulating sufficient RINs to cover 

their individual renewable volume 

obligation. It will not matter whether 

the obligated party used the renewable 

fuel themselves. An obligated party’s 

obligation will be to ensure that a 

certain amount of renewable fuel was 

used, either by themselves or by 

someone else, and the RIN is evidence 

that this occurred for a certain volume 

of renewable fuel. Exporters of 

renewable fuel will also be required to 

acquire RINs in sufficient quantities to 

cover the volume of renewable fuel 

exported. RINs claimed for compliance 

purposes by obligated parties will thus 

represent renewable fuel actually 

consumed as motor vehicle fuel in the 

U.S. 

RINs are valid for compliance 

purposes for the calendar year in which 

they are generated, or the following 

calendar year. This approach to RIN life 

is consistent with the Act’s prescription 

that credits be valid for compliance 

purposes for 12 months as of the date of 

generation, where credits are generated 

at the end of a year when compliance is 

determined. An obligated party can 

either use RINs to demonstrate 

compliance, or can transfer RINs to any 

other party. If an obligated party is not 

able to accumulate sufficient RINs for 

compliance in a given year, it can carry 

a deficit over to the next year so long as 

the full deficit and obligation is covered 

in the next year. 

In order to ensure that previous year 

RINs are not used preferentially for 

compliance purposes in a manner that 

would effectively circumvent the 

limitation that RINs be valid for only 12 

months after the year generated, we are 

setting a cap on the use of RINs 

generated the previous year when 

demonstrating compliance with the 

renewable volume obligation for the 

current year. The cap will mean that no 

more than 20 percent of a current year 

obligation can be satisfied using RINs 

from the previous year. In this manner 

there is no ability for excess renewable 

fuel use in successive years to cause an 

accumulation of RINs to significantly 

depress renewable fuel demand in any 

future year. In keeping with the Act, 

excess RINs not used in the year they 

are generated or in the subsequent year 

will expire. 

Section III.D provides more details on 

how obligated parties must use RINs for 

compliance purposes. 

6. How Will the Trading Program Work? 

Renewable fuel producers and 

importers will be required to generate 

RINs when they produce or import a 

batch of renewable fuel (unless, for 

importers, the RINs have been assigned 

by a foreign producer registered with 

EPA). They will then be required to 

transfer those RINs along with the 

renewable fuel batches that they 

represent whenever they transfer 

ownership of the batch to another party. 

Likewise any other non-obligated party 


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that takes ownership of a volume of 

renewable fuel with RINs will be 

required to transfer those RINs with a 

volume of renewable fuel. The RIN can 

be separated from renewable fuel only 

by obligated parties (at the point when 

they take ownership of the batch) or a 

party that converts the renewable fuel 

into motor vehicle fuel (such as upon 

blending with gasoline or diesel). 

Once a RIN is separated from a 

volume of renewable fuel, it can be used 

for compliance purposes, banked, or 

traded to another party. Separated RINs 

can be transferred to any party any 

number of times. Recordkeeping and 

reporting requirements will apply to any 

party that takes ownership of RINs, 

whether through the ownership of a 

batch of renewable fuel or through the 

transfer of separated RINs. 

Thus obligated parties can acquire 

RINs directly through the purchase of 

renewable fuel with assigned RINs or 

through the open market for RINs that 

is allowed under this proposal. Section 

III.E provides more details on how our 

RIN trading program will work. 

7. How Will the Program Be Enforced? 

As in all EPA fuel regulations, there 

is a system of registration, 

recordkeeping, and reporting 

requirements for obligated parties, 

renewable producers and importers 

(RIN generators), and any parties that 

procure or trade RINs either as part of 

their renewable purchases or separately. 

In most cases, the recordkeeping 

requirements are not significantly 

different from what these parties might 

be doing already as a part of normal 

business practices. The lynch pin to the 

compliance program, however, is the 

unique RIN number itself coupled with 

an electronic reporting system where 

RIN generation, RIN use, and RIN 

transactions will be reported and 

verified. Thus, EPA, as well as industry 

can have confidence that invalid RINs 

are not generated and that there is no 

double counting. 

C. Voluntary Green Labeling Program 

In the proposal EPA asked for 

comments on the idea of creating a 

voluntary labeling program to encourage 

the adoption and use of practices that 

minimize the environmental concerns 

associated with renewable fuel 

production. The proposal suggested 

adding a ‘‘G’’ (for green) to the end of 

the RIN of a fuel to indicate that a gallon 

of renewable fuel was produced with 

the combination of best farming 

practices and environmentally friendly 

production methods and facilities. EPA 

received a number of comments on this 

idea. 

The majority of respondents were 

very supportive of voluntary labeling 

and encouraged EPA to establish this 

program through this final rulemaking. 

Two commenters opposed the labeling 

concept, telling EPA that the number 

and complexity of issues associated 

with fuel production, and particularly 

with farming practices, would make 

such a program impractical and difficult 

to implement. EPA also was told that it 

would be hard to audit such a program. 

Most commenters agreed that using the 

RIN to host the label makes sense, 

however the use of ‘‘G’’ for green fuel 

is insufficient to capture the full range 

of environmental impacts of renewable 

fuel production and that it would be 

difficult for EPA to establish an 

appropriate cut-off point for 

determining which fuel qualified for a 

‘‘G’’ designation. Several respondents 

suggested that EPA instead use a more 

continuous scale based on energy or 

lifecycle greenhouse gas emissions. 

A well designed voluntary labeling 

program could permit producers and 

blenders to distinguish their fuels in the 

marketplace and allow consumers to 

express preferences for ‘‘green’’ 

products through their fuel purchases. 

While such a program could be valuable 

to producers, blenders, and consumers, 

given the range of comments received 

on the topic, we believe it is important 

first to continue the dialogue with the 

various stakeholders to ensure that the 

program adequately addresses the issues 

raised prior to putting any such program 

in place. Thus we are not finalizing a 

voluntary labeling program. We will 

continue to investigate the issues 

surrounding a voluntary labeling 

program and the various ways in which 

it could be designed. In particular we 

are interested in further exploring 

methods to incorporate lifecycle 

impacts into a voluntary labeling 

program and consumer expectations for 

such ‘‘green’’ labeling. 

III. Complying With the Renewable 

Fuel Standard 

According to the Energy Act, the RFS 

program places obligations on 

individual parties such that the 

renewable fuel volumes shown in Table 

I.B–1 are used as motor vehicle fuel in 

the U.S. each year. To accomplish this, 

the Agency must calculate and publish 

a standard by November 30 of each year 

which is applicable to every obligated 

party. On the basis of this standard each 

obligated party determines the volume 

of renewable fuel that it must ensure is 

consumed as motor vehicle fuel. In 

addition to setting the standard, we 

must clarify who the obligated parties 

are and what volumes of gasoline are 

subject to the standard. Obligated 

parties must also know which 

renewable fuels are valid for RFS 

compliance purposes, and the relative 

values of each type of renewable fuel in 

terms of compliance. This section 

discusses how the annual standard is 

determined and which parties and 

volumes of gasoline will be subject to 

the requirements. 

Because renewable fuels are not 

produced or distributed evenly around 

the country, some obligated parties will 

have easier access to renewable fuels 

than others. As a result, the RFS 

program depends on a robust trading 

program. This section also describes all 

the elements of our trading program. 

A. What Is the Standard That Must Be 

Met? 

1. How Is the Percentage Standard 

Calculated? 

Table I.B–1 shows the required total 

volume of renewable fuel specified in 

the Act for 2007 through 2012. The 

renewable fuel standard is based 

primarily on (1) the 48-state gasoline 

consumption volumes projected by EIA 

(as the Act exempts Hawaii and Alaska, 

subject to their right to opt-in, as 

discussed in Section III.C.4), and (2) the 

volume of renewable fuels required by 

the Act for the coming year. The 

renewable fuel standard will be 

expressed as a volume percentage of 

gasoline sold or introduced into 

commerce in the U.S., and will be used 

by each refiner, blender or importer to 

determine their renewable volume 

obligation. The applicable percentage is 

set so that if each regulated party meets 

the percentage and total gasoline 

consumption does not fall short of EIA 

projections then the total amount of 

renewable fuel used will meet the total 

renewable fuel volume specified in 

Table I.B–1. 

In determining the applicable 

percentage for a calendar year, the Act 

requires EPA to adjust the standard to 

prevent the imposition of redundant 

obligations on any person and to 

account for the use of renewable fuel 

during the previous calendar year by 

exempt small refineries, defined as 

refineries that process less than 75,000 

bpd of crude oil. As a result, in order 

to be assured that the percentage 

standard will in fact result in the 

volumes shown in Table I.B–1, we must 

make several adjustments to what is 

otherwise a simple calculation. 

As stated, the renewable fuel standard 

for a given year is basically the ratio of 

the amount of renewable fuel specified 

in the Act for that year to the projected 

48-state non-renewable gasoline volume 


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7Under the Act, small refineries are those with 

75,000 bbl/day or less average aggregate daily crude 

oil throughput. 

8Small refiners are those entities who produced 

gasoline from crude oil in 2004, and who meet the 

crude processing capability (no more than 155,000 

barrels per calendar day, bpcd) and employee (no 

more than 1500 people) criteria as specified in 

previous EPA fuel regulations. 

9As discussed in section III.C.3.a of this 

preamble, the small refinery exemption may be 

extended under 211(o)(9)(A)(ii) or (B) of the Clean 

Air Act as amended by the Energy Policy Act. 

10 ‘‘Calculation of the Small Refiner/Small 

Refinery Fraction for the Renewable Fuel Program,’’ 

memo to the docket from Christine Brunner, ASD, 

OTAQ, EPA September 2006. 

for that year. While the required amount 

of total renewable fuel for a given year 

is provided by the Act, the Act requires 

EPA to use an EIA estimate of the 

amount of gasoline that will be sold or 

introduced into commerce for that year. 

The level of the percentage standard is 

reduced if Alaska, Hawaii, or a U.S. 

territory choose to participate in the 

RFS program, as gasoline produced in or 

imported into those states or territories 

would then be subject to the standard. 

Should any of these states or territories 

opt into the RFS program, the projected 

gasoline volume would increase above 

that consumed in the 48 contiguous 

states. 

In the proposal, we stated that EIA 

had indicated that the best estimation of 

the coming year’s gasoline consumption 

is found in Table 5a (U.S. Petroleum 

Supply and Demand: Base Case) of the 

October issue of the monthly EIA 

publication Short-Term Energy Outlook 

which publishes quarterly energy 

projections. Commenters on this issue 

supported the use of the October issue 

of EIA’s Short-Term Energy Outlook 

(STEO), Table 5a, for the purpose of 

estimating the next year’s gasoline 

consumption, and we have used the 

October 2006 STEO values for 

estimating 2007 gasoline consumption 

for this final rule. 

The gasoline volumes in the STEO 

include renewable fuel use. As 

discussed below in Section III.C.1, the 

renewable fuel obligation does not 

apply to renewable blenders. Thus, the 

gasoline volume used to determine the 

standard must be the non-renewable 

portion of the gasoline pool, in order to 

achieve the volumes of renewables 

specified in the Act. In order to get a 

total non-renewable gasoline volume, 

we must subtract the renewable fuel 

volume from the total gasoline volume. 

EIA has indicated that the best 

estimation of the coming year’s 

renewable fuel consumption is found in 

Table 11 (U.S. Renewable Energy Use by 

Sector: Base Case) of the October issue 

of the STEO. As with the gasoline 

projections discussed above, we have 

used the October 2006 STEO values for 

estimating 2007 renewable fuel values 

for this final rule. 

The Act exempts small refineries 7

from the RFS requirements until the 

2011 compliance period. As discussed 

in Section III.C.3.a, as proposed, EPA is 

also exempting small refiners 8 from the 

RFS requirements until 2011, and is 

treating small refiner gasoline volumes 

the same as small refinery gasoline 

volumes. Since small refineries and 

small refiners are exempt from the 

program until 2011, EPA is excluding 

their gasoline volumes from the overall 

non-renewable gasoline volume used to 

determine the applicable percentage. 

EPA believes this is appropriate because 

the percentage standard should be based 

only on the gasoline subject to the 

renewable volume obligation. Because 

small refineries and small refiners are 

exempt (unless they waive exemption) 

only through the 2010 compliance 

period when the exemption ends, 

calculation of the standard for calendar 

year 2011 and beyond will include 

small refinery and small refiner 

volumes.9 Using information from 

gasoline batch reports submitted to EPA, 

EIA data, and input from the California 

Air Resources Board regarding 

California small refiners, we are 

finalizing a small refiner exemption 

adjustment to the standard of a constant 

13.5%,10 consistent with the proposal. 

The Act requires that the small 

refinery adjustment also account for 

renewable fuels used during the prior 

year by small refineries that are exempt 

and do not participate in the RFS 

program. Accounting for this volume of 

renewable fuel would reduce the total 

volume of renewable fuel use required 

of others, and thus directionally would 

reduce the percentage standard. 

However, as discussed in the proposal, 

there are no such data available, the 

amount of renewable fuel that would 

qualify (i.e., that was used by exempt 

small refineries and small refiners but 

not used as part of the RFS program) is 

expected to be very small and would not 

significantly change the resulting 

percentage standard. Because whatever 

renewables small refiners and small 

refineries blend will be reflected as RINs 

available in the market, there is no need 

for a separate accounting of their 

renewable fuel use in the equation used 

to determine the standard. We thus 

proposed that this value be zero, and we 

are finalizing the equation as such. 

We also proposed not to include 

renewable fuel used in Alaska, Hawaii, 

or U.S. territories when subtracting 

renewable fuel volumes from the 

anticipated total gasoline volumes in 

EIA projections. The Act requires that 

the renewable fuel be consumed in the 

contiguous 48 states unless Alaska, 

Hawaii, or a U.S. territory opt-in. 

However, because renewable fuel 

produced in Alaska, Hawaii, and U.S. 

territories is unlikely to be transported 

to the contiguous 48 states, including 

their renewable fuel volumes in the 

calculation of the standard would not 

serve the purpose intended by the Act 

of ensuring that the statutorily required 

renewable fuel volumes are consumed 

in the 48 contiguous States. We are 

finalizing the exclusion of these areas’ 

renewable fuel use as proposed. 

We stated that any deficit carryover 

from 2006 would increase the 2007 

standard. Since renewable fuel use in 

2006 exceeded the 2.78 percent default 

standard, there is no deficit to carry over 

to 2007. Beginning with the 2007 

compliance period, when annual 

individual party compliance replaces 

collective compliance, any deficit is 

calculated for an individual party and is 

included in the party’s Renewable 

Volume Obligation (RVO) 

determination, as discussed in Section 

III.A.4. 

In summary, the total projected nonrenewable gasoline volumes from which 

the annual standard is calculated is 

based on EIA projections of gasoline 

consumption in the contiguous 48 

states, adjusted by a constant percentage 

of 13.5% to account for small refinery/ 

refiner volume, with built-in correction 

factors to be used when and if noncontiguous states and territories opt-in 

to the program. If actual gasoline 

consumption were to exceed the EIA 

projection, the result would be that 

renewable fuel volumes will exceed the 

statutory requirements. Conversely, if 

actual gasoline consumption was less 

than the EIA projection for a given year, 

theoretically a renewable fuel shortfall 

could occur. However, our projections 

of renewable fuel use due to market 

demand would make a shortfall 

extremely unlikely regardless of the 

error in gasoline consumption 

projections. 

The following formula will be used to 

calculate the percentage standard: 


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11 ‘‘Calculation of the Renewable Fuel Standard’’ 

memo to the docket from Christine Brunner, ASD, 

OTAQ, EPA, September 2006. 12 ‘‘Calculation of the Renewable Fuel Standard— 

Revised’’ memo to the docket from Christine 

Brunner, ASD, OTAQ, EPA, April 2007. 

13The higher (or gross or upper) heating value is 

used in all Btu calculations for EIA’s Annual Energy 

Review and in related EIA publications (see 

discussion in EIA’s Annual Energy Review, 

Appendix A, Thermal Conversion Factors). 

14The lower heating value (LHV) is used to 

represent energy content in the context of setting 

Equivalence Values as described in Section III.B.4 

because it more accurately reflects the energy 

available in the fuel to produce work. 

RFStd RFV

G R GS RS GE i

i

ii i i i

= × −

( ) − + − ( ) − 100 Celli

Where: 

RFStdi = Renewable Fuel standard in year i, 

in percent. 

RFVi = Annual volume of renewable fuels 

required by section 211(o)(2)(B) of the 

Act for year i, in gallons. 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states, in year i, in 

gallons. 

Ri = Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in the 48 contiguous states, in year i, in 

gallons. 

GSi = Amount of gasoline projected to be 

used in Alaska, Hawaii, or a U.S. 

territory in year i if the state or territory 

opts-in, in gallons. 

RSi = Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in Alaska, Hawaii, or a U.S. territory in 

year i if the state or territory opts-in, in 

gallons. 

GEi = Amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons 

(through 2010 only unless exemption 

extended under §§ 211(o)(9)(A)(ii) or 

(B)). Equivalent to 0.135*(Gi¥Ri). 

Celli = Beginning in 2013, the amount of 

renewable fuel that is required to come 

from cellulosic sources, in year i, in 

gallons (250,000,000 gallons minimum). 

After 2012 the Act requires that the 

applicable volume of required 

renewable fuel specified in Table I.B–1 

include a minimum of 250 million 

gallons that are derived from cellulosic 

biomass. As shown in Table III.A.2–1 

below, we have estimated this value 

(250 million gallons) as a percent of an 

obligated party’s production for 2013. 

Thus, an obligated party will be subject 

to two standards in 2013 and beyond, a 

non-cellulosic standard and a cellulosic 

standard. We are therefore also 

finalizing the following formula for 

calculating the cellulosic standard that 

is required beginning in 2013: 

RF

G R GS RS ii i i

Cell Cell i

i = × ( ) − + − ( ) 100

Where, except for RFCelli, the variable 

descriptions are as discussed above. The 

definition of RFCelli is: 

RFCelli = Renewable Fuel Cellulosic 

Standard in year i, in percent 

Note that after 2012 cellulosic RINs 

cannot be used to satisfy the noncellulosic RFS standard (RFStdi). The 

amount of renewable fuel that is 

required to come from cellulosic sources 

(Celli) is a fixed amount. 

We are not finalizing regulations that 

would specify the criteria under which 

a state could petition the EPA for a 

waiver of the RFS requirements, nor the 

ramifications of Agency approval of 

such a waiver in terms of the level or 

applicability of the standard. As 

discussed in the proposal, there was no 

clear way to include such a provision in 

the context of the program being 

finalized. As a result, the formula for the 

standard shown above does not include 

any components to account for Agency 

approval of a state petition for a waiver 

of the RFS requirements. Should EPA 

grant such a waiver in the future, it will 

determine at that time what adjustments 

to make to the standard. 

2. What Are the Applicable Standards? 

As discussed in the proposal, EPA 

will set the percentage standard for each 

upcoming year based on the most recent 

EIA STEO projections, and using the 

other sources of information as noted 

above. EPA will publish the standard in 

the Federal Register by November 30 of 

the preceding year. The standards are 

used to determine the renewable 

volume obligation based on an obligated 

party’s total gasoline production or 

import volume in a calendar year, 

January 1 through December 31. The 

percentage standards do not apply on a 

per gallon basis. An obligated party will 

calculate its Renewable Volume 

Obligation (discussed in Section III.A.4) 

using the annual standard. 

In the NPRM, we estimated the 

standards for 2007 and later using data 

available at the time and the formulas 

discussed above.11 We have revised 

these values based on more recent data, 

and using EIA’s October 2006 STEO 

gasoline and renewable fuel 

consumption projections.12 In the 

proposal, we had used the lower heating 

value of ethanol for converting from Btu 

to gallons of ethanol for the purpose of 

calculating the standard. However, for 

this final rule, we have used the higher 

heating value of ethanol as 

recommended by commenters, to be 

consistent with EIA practices.13 14

Variables related to state or territory optins were set to zero since we do not 

have any information related to their 

participation at this time. As mentioned 

earlier, we estimate the small refinery 

and small refiner fraction to be 13.5%. 

The exemption for small refineries and 

small refiners ends at the end of the 

2010 compliance period, unless 

extended as discussed in Section 

III.C.3.a. Based on all of these factors, 

the standard for 2007 is 4.02%. 

Projected values of the standard for 

2008 and beyond are shown in Table 

III.A.2–1. 

TABLE III.A.2–1.—PROJECTED STANDARDS

Year Projected standard Cellulosic standard 

2008 ................................................................... 4.63% ............................................................... Not applicable. 

2009 ................................................................... 5.21% ............................................................... Not applicable. 

2010 ................................................................... 5.80% ............................................................... Not applicable. 

2011 ................................................................... 5.38% ............................................................... Not applicable. 

2012 ................................................................... 5.42% ............................................................... Not applicable. 

2013+ ................................................................. 5.24% min. (non-cellulosic) .............................. 0.18% min. 


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Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 23913 

As discussed in Section II.A.5, for 

calendar year 2013 and thereafter, the 

applicable volumes will be determined 

in accordance with separate statutory 

provisions that include EPA 

coordination with the Departments of 

Agriculture and Energy, and a review of 

the program during calendar years 2006 

through 2012. The Act specifies that this 

review consider the impact of the use of 

renewable fuels on the environment, air 

quality, energy security, job creation, 

and rural economic development, and 

the expected annual rate of future 

production of renewable fuels, 

including cellulosic ethanol. We intend 

to conduct another rulemaking as we 

approach the 2013 timeframe that 

would include our review of these 

factors. That rulemaking will present 

our conclusions regarding the 

appropriate applicable volume of 

renewable fuel for use in calculating the 

renewable fuel standard for 2013 and 

beyond. The program finalized by 

today’s rule will continue to apply after 

2012, though some elements may be 

modified in the rulemaking setting the 

standards for 2013 and beyond. Today’s 

rule does not contain a mechanism for 

establishing a post-2012 standard. 

3. Compliance in 2007 

The Energy Act requires that EPA 

promulgate regulations to implement 

the RFS program, and if EPA did not 

issue such regulations then a default 

standard for renewable fuel use would 

apply in 2006. On December 30, 2005 

we promulgated a direct final rule to 

interpret and implement the application 

of the statutory default standard of 2.78 

percent in calendar year 2006 (70 FR 

77325). However, the Act provides no 

default standard for any other year. 

In the NPRM we stated our 

expectation that, due to the limited time 

available for this rulemaking, we would 

be unable to publish the final rule and 

have it become effective by January 1, 

2007. We discussed several ways that 

we could specify how, and for what 

time periods, the applicable standard 

and other program requirements would 

apply to regulated parties for gasoline 

produced during 2007. We discussed a 

collective compliance approach similar 

to that applied in 2006, as well as a ‘‘full 

year’’ approach that would have based 

the renewable volume obligation for 

each obligated party on all gasoline 

produced starting on January 1, 2007 

regardless of the effective date of the 

rule. However, due to a number of 

issues with these approaches, we 

proposed a ‘‘prospective’’ approach in 

which the renewable fuel standard 

would be applied to only those volumes 

of gasoline produced after the effective 

date of the final rule. Essentially the 

renewable volume obligation for 2007 

would be based on only those volumes 

of gasoline produced or imported by an 

obligated party prospectively from the 

effective date of the rulemaking forward, 

and renewable producers would not 

have to begin generating RINs and 

maintaining the necessary records until 

this same date. 

We received no comments supporting 

the alternative ‘‘full year’’ approach to 

2007 compliance. However, several 

parties expressed a preference for either 

a collective compliance approach for 

2007, or if not that then delaying 

implementation of the comprehensive 

program to January 1, 2008. They argued 

that regulated parties needed additional 

time to put into place the sophisticated 

RIN tracking systems that would be 

required. The additional time would 

also allow regulated parties to debug the 

systems, train personnel, and put 

support programs into place. The 

American Coalition for Ethanol also 

argued that the prospective approach 

did not guarantee that the total 

renewable fuel volumes required by the 

Act for 2007 would actually be used in 

2007, whereas a collective compliance 

approach would. Parties in favor of a 

collective compliance approach argued 

that EPA has the authority to implement 

such an approach despite the fact that 

the Act does not explicitly give EPA this 

authority, and also argued that there 

was no need to include any form of 

credit carryover under a collective 

compliance approach. 

However, a number of refiners and 

their associations opposed a collective 

compliance approach to 2007 and 

expressed strong support for the 

proposed prospective approach. They 

argued that a start date at least 60 days 

from the date of publication of the final 

rule would provide sufficient time to 

obligated parties for making the 

necessary adjustments for compliance. 

They also argued that they should be 

afforded the opportunity to participate 

as soon as possible in the trading 

program, which the collective 

compliance approach used for 2006 

would preclude for 2007. 

We continue to believe that a 

collective compliance approach is not 

appropriate for 2007. The Energy Act 

requires us to promulgate regulations 

that provide for the generation of credits 

by any person who over complies with 

their obligation. It also stipulates that a 

person who generates credits must be 

permitted to use them for compliance 

purposes, or to transfer them to another 

party. These credit provisions have 

meaning only in the context of an 

individual obligation to meet the 

applicable standard. Delaying a credit 

program until 2008 would mean the 

credit provisions have no meaning at all 

for 2007, since under a collective 

compliance approach no individual 

facility or company would be liable for 

meeting the applicable standard. 

Including a ‘‘collective’’ credit or deficit 

carryforward as part of a collective 

compliance program would also not 

fully implement the credit provisions of 

the Act. The prospective compliance 

approach, in contrast, not only provides 

obligated parties with the opportunity to 

generate credits, but also provides the 

industry with the certainty they need to 

comply and is relatively straightforward 

to implement. 

Rather than requiring the program to 

begin on the effective date of the rule as 

proposed (60 days following publication 

in the Federal Register), we are 

finalizing a start date of September 1, 

2007. From this date forward, the 

renewable fuel standard will be 

applicable to all gasoline produced or 

imported, and all renewable fuels 

produced or imported will have to be 

assigned a RIN. All regulated parties 

must be registered by this date, and the 

recordkeeping responsibilities will also 

begin. By setting such a date, industry 

will be able to plan with confidence to 

start complying upon signature of the 

rule, rather than having the start date 

depend upon the timing of publication 

of this final rule in the Federal Register. 

We recognize the concerns expressed in 

comments that time is needed to 

prepare Information Technology (IT) 

systems to comply with the program. 

However, we believe that a September 1, 

2007 start date will provide sufficient 

time. The final rule is in most respects 

consistent with the NPRM, and based on 

discussions with industry, plans for 

implementation are already underway. 

Furthermore, a September 1, 2007 start 

date will likely provide regulated 

parties some additional time to prepare 

in comparison to simply setting the start 

date as 60 days following publication of 

the rule. 

As stated in the NPRM, we recognize 

that the prospective approach to 2007 

compliance will not guarantee by 

regulation that the total renewable fuel 

volumes required by the Act for 2007 

would actually be used in 2007. 

However, current projections from the 

Energy Information Administration 

(EIA) on the volume of renewable fuel 

expected to be produced in 2007 

indicate that the Act’s required volumes 

will be exceeded by a substantial margin 

due to the relative economic value of 

renewable fuels in comparison to 

gasoline. We are confident that the 

combined effect of the regulatory 


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15The statutory default standard for 2006 is the 

one exception to this, since it directly establishes 

a renewable fuel obligation applicable to refiners 

and importers in the event that EPA does not 

promulgate regulations. 

16As discussed below, for purposes of this 

rulemaking, the regulations separate ‘‘biodiesel’’ as 

defined in the Energy Act, into biodiesel (diesels 

that meet the Energy Act’s definition and are a 

mono-alkyl ester) and renewable diesel (other 

diesels that meet the Energy Act’s definition but are 

not mono-alkyl esters). 

requirements for 2007 and the expected 

market demand for renewable fuels will 

lead to greater renewable fuel use in 

2007 than is called for under the Act. 

Current renewable production already 

exceeds the rate required for all of 2007, 

and as discussed in Section VI, capacity 

is expected to continue to grow. 

Furthermore, refiners and importers are 

not required to meet any requirements 

under the Act until EPA adopts the 

regulations, and EPA is authorized to 

consider appropriate lead time in 

establishing the regulatory 

requirements.15 Under this option we 

believe there will be reasonable leadtime for regulated parties to meet their 

2007 compliance obligations. While no 

option before us is perhaps totally 

consistent with all of the provisions of 

the Act, we believe the rule as adopted 

does the best job possible given the 

circumstances of implementing all of 

the provisions of the Act for 2007. 

4. Renewable Volume Obligations 

In order for an obligated party to 

demonstrate compliance, the percentage 

standards described in Section III.A.2 

which are applicable to all obligated 

parties must be converted into the 

volume of renewable fuel each obligated 

party is required to satisfy. This volume 

of renewable fuel is the volume for 

which the obligated party is responsible 

under the RFS program, and is referred 

to here as its Renewable Volume 

Obligation (RVO). 

The calculation of the RVO requires 

that the standard shown in Table 

III.A.2–1 for a particular compliance 

year be multiplied by the gasoline 

volume produced by an obligated party 

in that year. To the degree that an 

obligated party did not demonstrate full 

compliance with its RVO for the 

previous year, the shortfall is included 

as a deficit carryover in the calculation. 

The equation used to calculate the RVO 

for a particular year is shown below: 

RVOi = Stdi × GVi + Di¥1

Where: 

RVOi = The Renewable Volume Obligation 

for the obligated party for year i, in 

gallons. 

Stdi = The RFS program standard for year i, 

in percent. 

GVi = The non-renewable gasoline volume 

produced by an obligated party in year 

i, in gallons. 

Di¥1 = Renewable fuel deficit carryover from 

the previous year, in gallons. 

The Energy Act only permits a deficit 

carryover from one year to the next if 

the obligated party achieves full 

compliance with its RVO including the 

deficit carryover in the second year. 

Thus deficit carryovers could not occur 

two years in succession. They could, 

however, occur as frequently as every 

other year for a given obligated party. 

The calculation of an obligated party’s 

RVO is necessarily retrospective, since 

the total gasoline volume that it 

produces in a calendar year will not be 

known until the year has ended. 

However, the obligated party will have 

an incentive to project gasoline 

volumes, and thus the RVO, throughout 

the year so that it can spread its efforts 

to comply across the entire year. Most 

refiners and importers will be able to 

project their annual gasoline production 

volumes with a minimum of uncertainty 

based on their historical operations, 

capacity, plans for facility downtimes, 

knowledge of gasoline markets, etc. 

Even if unforeseen circumstances (e.g., 

hurricane, unit failure, etc.) significantly 

reduced the production volumes in 

comparison to their projections, their 

RVO will likewise be reduced 

proportionally and their ability to 

comply with the RFS requirements will 

be only minimally affected. Each 

obligated party’s projected RVO for a 

given year becomes more accurate as 

that year progresses, but the obligated 

party should nevertheless have a 

sufficiently accurate estimate of its RVO 

at the beginning of the year to allow it 

to begin its efforts to comply. 

B. What Counts as a Renewable Fuel in 

the RFS Program? 

Section 211(o) of the Clean Air Act 

defines ‘‘renewable fuel’’ and specifies 

many of the details of the renewable 

fuel program. The following section 

provides EPA’s views and 

interpretations on issues related to what 

fuels may be counted towards 

compliance with the RVO, and how 

they are counted. 

1. What Is a Renewable Fuel That Can 

Be Used for Compliance? 

The statutory definition of renewable 

fuel includes cellulosic ethanol and 

waste derived ethanol. It includes 

biodiesel, as defined in the Energy 

Act.16 It also includes all motor vehicle 

fuels that are produced from biomass 

material such as grain, starch, oilseeds, 

animal, or fish materials including fats, 

greases and oils, sugarcane, sugar beets, 

tobacco, potatoes or other biomass (such 

as bagasse from sugar cane, corn stover, 

and algae and seaweed). In addition, it 

includes motor vehicle fuels made using 

a feedstock of natural gas if produced 

from a biogas source such as a landfill, 

sewage waste treatment plant, feedlot, 

or other place where decaying organic 

material is found. 

According to the Act, the motor 

vehicle fuels must be used ‘‘to replace 

or reduce the quantity of fossil fuel 

present in a fuel mixture used to operate 

a motor vehicle.’’ Some motor vehicle 

fuels can be used in both motor vehicles 

or nonroad engines or equipment. For 

example, highway gasoline and diesel 

fuel are often used in both highway and 

off-highway applications. Compressed 

natural gas can likewise be used in 

either highway or nonroad applications. 

For purposes of the renewable fuel 

program, EPA considers a fuel to be a 

‘‘motor vehicle fuel’’ and to be ‘‘a fuel 

mixture used to operate a motor 

vehicle,’’ based on its potential for use 

in highway and nonroad vehicles, 

without regard to whether it, in fact, is 

used in a highway vehicle application. 

EPA does not believe that the much 

more complex and costly regulatory 

scheme that would be needed to track 

motor vehicle fuel use versus off-road 

fuel use would be justified. (As 

discussed further below, heaters and 

boilers are not considered highway or 

nonroad engine applications and 

renewable fuel produced or imported 

specifically for use in such equipment is 

not valid for compliance purposes 

under the RFS program.) If it is a fuel 

that could be used in highway vehicles, 

it will satisfy these parts of the 

definition of renewable fuel, whether it 

is later used in highway or nonroad 

applications. This will allow a motor 

vehicle fuel that otherwise meets the 

definition to be counted towards a 

party’s RVO without the need to track 

it to determine its actual application in 

a highway vehicle, and provided only 

that the producer does not know that 

the fuel will be used for a purpose other 

than highway and nonroad engine 

applications. This is also consistent 

with the requirement that EPA base the 

renewable fuel obligation on estimates 

of the entire volume of gasoline 

consumed, without regard to whether it 

is used in highway or nonroad 

applications. 

Renewable fuel as defined, may be 

made from a number of different types 

of feedstocks. For example, the FisherTropsch process can use methane gas 

from landfills as a feedstock, to produce 

diesel or gasoline. Vegetable oil made 


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from oilseeds such as rapeseed or 

soybeans can be used to make biodiesel 

or renewable diesel. Methane, made 

from landfill gas (biogas) can be used to 

make methanol, or can be used directly 

as a fuel in vehicles with engines 

designed to run on compressed natural 

gas. Also, some vegetable oils or animal 

fats can be processed in distillation 

columns in refineries to make gasoline; 

as such, the renewable feedstock serves 

as a ‘‘renewable crude,’’ and the 

resulting gasoline or diesel product 

would be a renewable fuel. This last 

example is discussed in further detail in 

Section III.B.3 below. 

As this discussion shows, the 

definition of renewable fuel in the Act 

is broad in scope, and covers a wide 

range of fuels. While ethanol is used 

primarily in combination with gasoline, 

the definition of renewable fuel in the 

Act is not limited to fuels that can be 

blended with gasoline. Various fuels 

that meet the definition of renewable 

fuel can be used in their neat form, such 

as ethanol, biodiesel, methanol or 

natural gas. Others, including ethanol 

may be used to produce a gasoline 

blending component (such as ETBE). At 

the same time, the RFS regulatory 

program is to ‘‘ensure that gasoline sold 

or introduced into commerce * * * 

contains the applicable volume of 

renewable fuel.’’ This applicable 

volume is specified as a total volume of 

renewable fuel on an aggregate basis. 

Congress also clearly specified that one 

renewable fuel, biodiesel, could be 

counted towards compliance even 

though it is not a gasoline component, 

and does not directly displace or replace 

gasoline. The Act is unclear on whether 

other fuels that meet the definition of 

renewable fuel, but are not used in 

gasoline, could also be used to 

demonstrate compliance towards the 

aggregate national use of renewable 

fuels. 

EPA interprets the Act as allowing 

regulated parties to demonstrate 

compliance based on any fuel that meets 

the statutory definition for renewable 

fuel, whether it is directly blended with 

gasoline or not. This would include neat 

alternative fuels such as ethanol, 

methanol, and natural gas that meet the 

definition of renewable fuel. This is 

appropriate for several reasons. First, it 

promotes the use of all renewable fuels, 

which will further the achievement of 

the purposes behind this provision. 

Congress did not intend to limit the 

program to only gasoline components, 

as evidenced by the provision for 

biodiesel, and the broad definition of 

renewable fuel evidences an intention to 

address more renewable fuels than those 

used with gasoline. Second, in practice 

EPA expects that the overwhelming 

volume of renewable fuel used to 

demonstrate compliance with the 

renewable fuel obligation would still be 

ethanol blended with gasoline. Finally, 

as discussed later, EPA’s compliance 

program is based on assigning volumes 

at the point of production, and not at 

the point of blending into motor vehicle 

fuel. This interpretation avoids the need 

to track renewable fuels downstream to 

ensure they are blended with gasoline 

and not used in their neat form; the 

gasoline that is used in motor vehicles 

is reduced by the presence of renewable 

fuels in the gasoline pool whether they 

are blended with gasoline or not. 

Comments received on this 

interpretation were favorable towards it. 

EPA continues to believe, therefore, that 

this approach is consistent with the 

intent of Congress and is a reasonable 

interpretation of the Act. One 

commenter indicated that a logical 

extension of this reasoning would 

provide that renewable fuel that could 

be used in motor vehicles is still a 

renewable fuel under the Act when used 

by renewable fuel producers in a boiler 

or heater. EPA disagrees. The term 

‘‘renewable fuel’’ means ‘‘motor vehicle 

fuel that * * * is used to replace or 

reduce the quantity of fossil fuel present 

in a fuel mixture used to operate a 

motor vehicle.’’ We believe that all but 

a trivial quantity of renewable fuels that 

can be used in motor vehicles will 

ultimately be used as motor vehicle fuel. 

Producers of ethanol biodiesel and other 

products that can be used as motor 

vehicle fuel can generally assume, 

therefore, that their products will be 

used in that way, and can assign RINs 

to their product without tracking its 

ultimate use. However, renewable fuel 

used onsite in a boiler or heater by a 

renewable fuel producer clearly is not a 

motor vehicle fuel used to replace or 

reduce the quantity of fossil fuel present 

in a fuel mixture used to operate a 

motor vehicle. 

Under the Act, renewable fuel 

includes ‘‘cellulosic biomass ethanol’’ 

and ‘‘waste derived ethanol’’, each of 

which is defined separately. Ethanol can 

be cellulosic biomass ethanol in one of 

two ways, as described below. 

a. Ethanol Made From a Cellulosic 

Feedstock 

The simplest process of producing 

ethanol is by fermenting sugar in sugar 

cane or beets, but ethanol can also be 

produced from starch in corn and other 

feedstocks by first converting the starch 

to sugar. Ethanol can also be produced 

from complex carbohydrates, such as 

the cellulosic portion of plants or plant 

products. The cellulose is first 

converted to sugars (by hydrolysis); then 

the same fermentation process is used as 

for sugar to make ethanol. Cellulosic 

feedstocks (composed of cellulose and 

hemicellulose) are currently more 

difficult and costly to convert to sugar 

than are starches. While the cost and 

difficulty are a disadvantage, the 

cellulosic process offers the advantage 

that a wider variety of feedstocks can be 

used. Ultimately with more feedstocks 

available from which to make ethanol 

more volume of ethanol can be 

produced. 

The Act provides the definition of 

cellulosic biomass ethanol, which 

states: 

‘‘The term ‘cellulosic biomass ethanol’ 

means ethanol derived from any 

lignocellulosic or hemicellulosic matter that 

is available on a renewable or recurring basis, 

including: 

(i) Dedicated energy crops and trees; 

(ii) Wood and wood residues; 

(iii) Plants; 

(iv) Grasses; 

(v) Agricultural residues; 

(vi) Animal wastes and other waste 

materials, and 

(viii) Municipal solid waste.’’ 

Examples of cellulosic biomass source 

material include rice straw, switch 

grass, and wood chips. Ethanol made 

from these materials would qualify 

under the definition as cellulosic 

ethanol. In addition to the above sources 

of feedstocks for cellulosic biomass 

ethanol, the Act’s definition also 

includes animal waste, municipal solid 

wastes, and other waste materials. 

‘‘Other waste materials’’ generally 

includes waste material such as sewage 

sludge, waste candy, and waste starches 

from food production, but for purposes 

of the definition of cellulosic ethanol 

discussed in III.B.1.b below, it can also 

mean waste heat obtained from an offsite combustion process. 

Although the definitions of 

‘‘cellulosic biomass ethanol’’ and 

‘‘waste derived ethanol’’ both include 

animal wastes and municipal solid 

waste in their respective lists of covered 

feedstocks, there remains a distinction 

between these types of ethanol. If the 

animal wastes or municipal solid wastes 

contain cellulose or hemicellulose, the 

resulting ethanol can be termed 

‘‘cellulosic biomass ethanol.’’ If the 

animal wastes or municipal solid wastes 

do not contain cellulose or 

hemicellulose, then the resulting 

ethanol is labeled ‘‘waste derived 

ethanol.’’ This is discussed further in 

Section III.B.1.c below. 


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23916 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

17On the other hand, wood from plants or trees 

that are grown as an energy crop may not qualify 

as a waste-derived fuel in an ethanol facility 

because such wood would not qualify as waste 

materials under this portion of the definition. 

Under the definition of renewable fuels and 

cellulosic biomass ethanol, however, such wood 

material could serve as a feedstock in a cellulosic 

ethanol plant, since these definitions do not restrict 

such feedstock to waste materials only. 

18The term ‘‘other waste materials’’ is also 

included in the portions of the definitions of 

‘‘cellulosic biomass ethanol’’ and ‘‘waste-derived 

ethanol’’ that identify feedstocks. The inclusion of 

off-site generated waste heat in the definition of 

‘‘other waste materials’’, however, applies only to 

the portion of the definition of cellulosic biomass 

ethanol that relates to displacement of fossil fuels, 

and does not apply to the term ‘‘other waste 

materials’’ as otherwise used in these definitions. 

19 In Section IX of today’s preamble we discuss 

our analysis of the lifecycle fuel impacts of the RFS 

rule, with respect to greenhouse gas (GHG) 

emissions. While we do account for fuel used in 

hauling materials to ethanol plants in our analysis, 

we are using average nationwide values, rather than 

data collected for individual plants. 

b. Ethanol Made From Any Feedstock in 

Facilities Using Waste Material To 

Displace 90 Percent of Normal Fossil 

Fuel Use 

The definition of cellulosic biomass 

ethanol in the Act also provides that 

ethanol made at any facility—regardless 

of whether cellulosic feedstock is used 

or not—may be defined as cellulosic if 

at such facility ‘‘animal wastes or other 

waste materials are digested or 

otherwise used to displace 90 percent or 

more of the fossil fuel normally used in 

the production of ethanol.’’ The 

statutory language suggests that there 

are two methods through which ‘‘animal 

and other waste materials’’ may be 

considered for displacing fossil fuel. 

The first method is the digestion of 

animal wastes or other waste materials. 

EPA has interpreted the term 

‘‘digestion’’ to mean the conversion of 

animal or other wastes into methane, 

which can then be combusted as fuel. 

We base our interpretation on the 

practice in industry of using anaerobic 

digesters to break down waste products 

such as manure into methane. 

Anaerobic digestion refers to the 

breakdown of organic matter by bacteria 

in the absence of oxygen, and is used to 

treat waste to produce renewable fuels. 

We note also that the digestion of 

animal wastes or other waste materials 

to produce the fuel used at the ethanol 

plant does not have to occur at the plant 

itself. Methane made from animal or 

other wastes offsite and then purchased 

and used at the ethanol plant would 

also qualify. 

The second method is suggested by 

the term ‘‘otherwise used’’ which we 

interpret to mean (1) the direct 

combustion of the waste materials as 

fuel at an ethanol plant, or (2) the use 

of thermal energy that itself is a waste 

product; e.g., waste heat that is obtained 

from an off-site combustion process 

such as a neighboring plant that has a 

furnace or boiler from which the waste 

heat is captured. With respect to the 

first meaning, ‘‘other waste materials’’ 

includes but is not limited to waste 

materials from tree farms (tops, 

branches, limbs, etc.), or waste materials 

from saw mills (sawdust, shavings and 

bark) as well as other vegetative waste 

materials such as corn stover, or sugar 

cane bagasse, that could be used as fuel 

for gasifier/boiler units at ethanol 

plants. Since these materials are not also 

used as a feedstock to starch-based 

ethanol plants, they are truly waste 

materials. Although these waste 

materials conceivably could be 

feedstocks to a cellulosic ethanol plant, 

their use in that manner is sufficiently 

challenging at the current time that EPA 

believes that such use does not subvert 

the intent of the definition.17 Since corn 

kernels can readily be used as a 

feedstock in a typical ethanol 

production facility, their use as a fuel 

for gasified/boiler units at a corn 

ethanol plant would not be considered 

use of ‘‘other waste material’’ for 

purposes of the definition of cellulosic 

biomass ethanol. 

Regarding the use of waste heat as a 

source of thermal energy, we note that 

there may be situations in which an offsite furnace, boiler or heater creates 

excess or waste heat that is not used in 

the process for which the thermal 

energy is employed. For example, a 

glass furnace generates a significant 

amount of waste heat that often goes 

unused. We have therefore included in 

the regulatory definition of cellulosic 

biomass ethanol waste heat generated 

from off-site sources in the definition of 

‘‘other waste materials’’ that can be used 

to displace 90% of the fossil fuel 

otherwise used at an ethanol production 

facility. 

Several commenters argued that 

because the source of the waste heat is 

ultimately a fossil fuel in most cases 

that it should not be considered an 

‘‘other waste material’’. The Agency 

recognizes that fossil fuel is ultimately 

the source of most waste heat, but it is 

also the case that waste heat that is 

uncaptured represents a loss of energy 

that could otherwise displace fossil fuel 

use elsewhere. Specifically, waste heat 

used at an ethanol plant would result in 

displacement of fossil fuel use at the 

plant. In writing the proposed rule, we 

were aware of the concern raised by the 

commenters and therefore proposed to 

restrict waste heat to off-site sources 

only. We believe that this approach 

minimizes the concern. We disagree 

with another commenter that such 

restriction would create a perverse 

incentive for facilities near ethanol 

plants to oversize its combustion units 

to sell waste heat to the neighboring 

ethanol facilities where it would be 

used to displace fossil fuel. It is highly 

unlikely that businesses would incur 

the additional expense of building an 

oversized combustion unit for the sale 

of waste heat. Also, the 2.5 gallon value 

given for one gallon of cellulosic 

ethanol as provided by the Act extends 

only through 2012. Any additional 

market value for waste heat used to 

qualify ethanol as cellulosic would 

therefore be of relatively short duration 

and not likely to warrant investment in 

oversized combustion units.18

The term ‘‘fossil fuel normally used in 

the production of ethanol’’ means fossil 

fuel used at the facility in the ethanol 

production process itself, rather than 

other phases such as trucks transporting 

product, and fossil fuel used to grow 

and harvest the feedstock. Therefore the 

diesel fuel that trucks consume in 

hauling wood waste from sawmills to 

the ethanol facility would not be 

counted in determining whether the 

90% displacement criterion has been 

met. We are interpreting it in this way 

because we believe the accounting of 

fuel use associated with transportation 

and other life cycle activities would be 

extremely difficult and in many cases 

impossible.19

Based on the operation of ethanol 

plants, we are viewing this definition to 

apply to waste materials used to 

produce thermal energy rather than 

electrical energy. Electrical usage at 

ethanol plants is used for lights and 

equipment not directly related to the 

production of ethanol. Also, the 

calculation of fossil fuel used to 

generate such electrical usage would be 

difficult because it is not always 

possible to track the source of electricity 

that is purchased off-site. Therefore, the 

final regulations consider displacement 

of 90 percent of fossil fuels at the 

ethanol plant to mean those fuels 

consumed on-site and that are used to 

generate thermal energy used to produce 

ethanol. 

One commenter suggested that 

electricity from cogeneration (i.e., 

combined heat and power) units be 

considered in determining the 

percentage of fossil fuel use that is 

displaced. The commenter claims that 

allowing consideration of electricity use 

would provide an incentive for 

cogeneration to be used at ethanol 

plants. Our findings regarding the use of 

electricity at ethanol plants remain the 

same—that is, it is not used as part of 


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Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 23917 

20 In the event that the ASTM specification D– 

6751 is succeeded with an updated specification in 

the future, EPA may revise the regulations 

accordingly at such time. Regulations cannot be 

promulgated that only reference ‘‘the most recent 

version’’ of an ASTM standard, since doing so 

would place the American Society for Testing and 

Materials in the position of a regulatory body. 

the heat source in ethanol production 

for economic reasons. We note also that 

the commenter did not present any 

evidence to the contrary. As such, we 

continue to maintain that electricity is 

not ‘‘normally used in the production of 

ethanol’’ and we are therefore only 

considering the displacement of fossil 

fuels associated with thermal energy at 

the plant. 

Owners who claim their product 

qualifies as cellulosic biomass ethanol 

based on the 90 percent fossil fuel 

displacement through the use of waste 

materials (i.e., animal wastes, and other 

waste materials) are required under 

today’s rule to keep records of fuel 

(waste-derived and fossil fuel) used for 

thermal energy for verification of their 

claims. They will also be required to 

track the fossil fuel equivalent of any 

off-site generated waste heat that is 

captured and which displaces fossil fuel 

used in the ethanol production process. 

Since such waste heat would typically 

be purchased through agreement with 

the off-site owner, we do not feel it 

burdensome for owners to track such 

information. Owners will therefore 

calculate the amount of energy in Btu’s 

associated with waste-derived fuels 

(including the fossil fuel equivalent 

waste heat), and divided by the total 

energy in Btus used to produce ethanol 

in a given year. Ethanol produced from 

such facilities will get the benefit of the 

2.5 ratio. (Section III.D.3.e discusses the 

requirements for owners of facilities that 

claim to have produced cellulosic 

ethanol under the 90 percent 

displacement provision, but which fail 

to meet those requirements.) 

c. Ethanol That Is Made From the NonCellulosic Portions of Animal, Other 

Waste, and Municipal Waste 

‘‘Waste derived ethanol’’ is defined in 

the Act as ethanol derived from ‘‘animal 

wastes, including poultry fats and 

poultry wastes, and other waste 

materials; * * * or municipal solid 

waste.’’ Both animal wastes and 

municipal solid waste are also listed as 

allowable feedstocks for the production 

of ‘‘cellulosic biomass ethanol.’’ When 

such feedstocks do not contain 

cellulose, however, the resulting ethanol 

is waste derived. Both waste-derived 

and cellulosic ethanol both are 

considered equivalent to 2.5 gallons of 

renewable fuel when determining 

compliance with the renewable volume 

obligation. 

d. Foreign Producers of Cellulosic and 

Waste-Derived Ethanol 

Some commenters stated that foreign 

ethanol producers should not be able to 

have their cellulosic or waste-derived 

ethanol treated in the same manner as 

domestic cellulosic or waste-derived 

ethanol under the RFS program because 

of the difficulty in verifying their 

compliance with the provisions 

discussed above. Today’s rule allows 

such producers to participate, provided 

they meet the requirements discussed in 

Section IV.D.2. of the preamble. The 

requirements for foreign producers of 

cellulosic or waste-derived ethanol are 

different than for domestic producers 

and allow for verification of 

compliance. 

2. What Is Biodiesel? 

The Act states that ‘‘The term 

‘renewable fuel’ includes * * * 

biodiesel (as defined in section 312(f)) 

of the Energy Policy Act of 1992.’’ This 

definition, as modified by Section 1515 

of the Energy Act states: 

The term ‘‘biodiesel’’ means a diesel fuel 

substitute produced from nonpetroleum 

renewable resources that meets the 

registration requirements for fuels and fuel 

additives established by the Environmental 

Protection Agency under section 7545 of this 

title, and includes biodiesel derived from 

animal wastes, including poultry fats and 

poultry wastes, and other waste materials, or 

municipal solid waste and sludges and oils 

derived from wastewater and the treatment of 

wastewater. 

This definition of biodiesel would 

include both mono-alkyl esters which 

meet the current ASTM specification D– 

6751–07 20 (the most common meaning 

of the term ‘‘biodiesel’’) that have been 

registered with EPA, and any non-esters 

that are intended for use in engines that 

are designed to run on conventional, 

petroleum-derived diesel fuel, have 

been registered with the EPA, and are 

made from any of the feedstocks listed 

above. 

To implement the above definition of 

biodiesel in the context of the RFS 

rulemaking while still recognizing the 

unique history and role of mono-alkyl 

esters meeting ASTM D–6751, we have 

divided the Act’s definition of biodiesel 

into two separate parts: Biodiesel 

(mono-alkyl esters) and non-ester 

renewable diesel. The combination of 

‘‘biodiesel (mono-alkyl esters)’’ and 

‘‘non-ester renewable diesel’’ in the 

regulations fulfills the Act’s definition 

of biodiesel. Commenters supported 

EPA’s approach in defining biodiesel in 

this manner. 

a. Biodiesel (Mono-Alkyl Esters) 

Under today’s rule, the term 

‘‘biodiesel (mono-alkyl esters)’’ means a 

motor vehicle fuel which: (1) Meets the 

registration requirements for fuels and 

fuel additives established by the 

Environmental Protection Agency under 

section 7545 of this title (Clean Air Act 

Section 211); (2) is a mono-alkyl ester; 

(3) meets ASTM specification D–6751– 

07; (4) is intended for use in engines 

that are designed to run on 

conventional, petroleum-derived diesel 

fuel, and (5) is derived from 

nonpetroleum renewable resources. 

b. Non-Ester Renewable Diesel 

The term ‘‘non-ester renewable 

diesel’’ means a motor vehicle fuel 

which: (1) Meets the registration 

requirements for fuels and fuel additives 

established by the Environmental 

Protection Agency under section 7545 of 

this title (Clean Air Act Section 211); (2) 

is not a mono-alkyl ester; (3) is intended 

for use in engines that are designed to 

run on conventional, petroleum-derived 

diesel fuel, and (4) is derived from 

nonpetroleum renewable resources. 

Current examples of a non-ester 

renewable diesel include: ‘‘Renewable 

diesel’’ produced by the Neste or UOP 

process, or diesel fuel produced by 

processing fats and oils through a 

refinery hydrotreating process. 

3. Does Renewable Fuel Include Motor 

Fuel That Is Made From Coprocessing a 

Renewable Feedstock With Fossil Fuels? 

Renewable fuels can be produced by 

processing biologically derived wastes 

such as animal fats, as well as other 

nonpetroleum based feedstocks in a 

traditional refinery—that is, a refinery 

that normally uses crude oil or other 

fossil fuel-based blendstocks as feeds to 

processing units. Such wastes are preprocessed so that they are in liquid form 

to enable their further processing in 

units at a traditional refinery. In the 

proposed rule, we defined such 

feedstocks as ‘‘biocrudes’’ and included 

a discussion on how the fuels resulting 

from these feedstocks should be 

counted. Our basic approach remains 

the same. We have changed the term 

‘‘biocrudes’’ to ‘‘renewable crudes’’, 

since we believe it is more accurate. We 

are providing additional discussion in 

this preamble on how renewable fuels 

are made from renewable crudes. 

The fuels resulting from the coprocessing of the pre-processed liquid 

form of these renewable crudes (i.e., 

those feedstocks listed in the definition 

of ‘‘renewable fuel’’ and, for biodiesel, 

in the statutory definition of 

‘‘biodiesel’’) in a traditional refinery are 


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23918 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

21Renewable crude-based fuels will need to be 

registered under the provisions contained in 40 CFR 

79 Part 4 before they can be sold commercially. 

22We are considering the volumes of renewable 

crude itself, not the feedstocks that are made into 

renewable crude. 

themselves indistinguishable from the 

gasoline and diesel products produced 

from crude oil. As such, the treatment 

of any resulting renewable fuel presents 

a particular complication in terms of 

RFS program compliance—namely, if 

such fuels are indistinguishable from 

gasoline and diesel produced from 

crude oil feedstocks, how are the 

volumes to be measured? Also, some 

renewable feedstocks are used to 

produce renewable diesel (discussed in 

Section III.B.2 above). In other 

circumstances renewable feedstocks are 

processed in dedicated facilities or 

units—that is, in either (1) facilities 

other than refineries that process fossil 

fuels, (2) equipment located within a 

traditional refinery but which is 

dedicated to renewable feedstocks, or 

(3) equipment located within a 

traditional refinery that processes 

renewable and conventional feedstocks 

but solely for the production of motor 

vehicle fuels. 

The processing approach for the 

renewable feedstock dictates whether 

the resulting fuel is distinguishable from 

crude oil-based fuels by virtue of its 

being made and stored separately from 

fossil fuels as discussed in further detail 

below. Therefore, our method for 

counting renewable fuels made from 

renewable feedstocks differ based on 

how the renewable feedstock is 

processed 

a. Definition of ‘‘Renewable Crudes’’ 

and ‘‘Renewable Crude-Based Fuels’’ 

Under some circumstances renewable 

feedstocks can be preprocessed into a 

liquid that is similar to petroleum-based 

feedstocks used in traditional refineries. 

We are classifying such liquids as 

‘‘renewable crudes,’’ and any motor 

vehicle fuel that is made from such 

liquids is defined broadly as ‘‘renewable 

crude-based fuel’’. 

There are three approaches that can 

be taken to making renewable fuels from 

renewable crudes. The first would 

include gasoline or diesel products 

resulting from the processing of 

renewable crudes in production units 

within refineries that simultaneously 

process crude oil and other petroleum 

based feedstocks. In these cases, the 

final product consists of a mixture of 

renewable fuel and fossil-based fuel, 

and may include both motor vehicle 

fuel and non-motor vehicle fuel. The 

second approach would include diesel 

and other products resulting from 

processing renewable crudes at a standalone facility that does not process any 

fossil fuels, or at a facility dedicated to 

renewable crudes within a traditional 

refinery.21 In this case, a batch of 

renewable crude used as feedstock to a 

production unit would replace crude oil 

or other petroleum based feedstocks 

which ordinarily would be the feedstock 

in that process unit. The third approach 

would be non-ester renewable diesel 

fuel produced by processing fats and 

oils through a refinery hydrotreating 

process. All three approaches can 

produce renewable fuel that is valid for 

compliance purposes under the RFS 

program, but the measurement of 

volumes produced and/or their 

associated Equivalence Values may 

differ. 

b. How Are Renewable Crude-Based 

Fuel Volumes Measured? 

As discussed above, some renewable 

feedstocks are processed in facilities 

other than refineries, or in equipment 

located within a traditional refinery but 

which is dedicated to renewable 

feedstocks. The resulting product is 

‘‘renewable diesel’’ (and such units may 

in the future also produce ‘‘renewable 

gasoline’’ though none is currently 

made in such dedicated facilities). In 

other situations, renewable crudes are 

coprocessed along with crude oils in 

traditional refineries, resulting in 

gasoline or diesel products that may be 

combinations of renewable and nonrenewable fuels. 

In the case of renewable crude 

coprocessed with fossil fuels in 

refineries, we are assuming that all of 

the renewable crude used as a feedstock 

in a refinery unit will end up as a 

renewable crude-based fuel that is valid 

for RFS compliance purposes. We are 

taking this approach because renewable 

crudes that are processed through 

distillate hydrotreaters are first preprocessed so that they are in liquid 

form, and such liquid produces diesel 

fuel in volumes approximately equal to 

the amount that is input to the 

hydrotreater. We are assuming that 

renewable crudes could also be 

processed in other process units at 

refineries to make gasoline. The 

renewable crude processed at a refinery 

is functionally equivalent to crude oil, 

and the end products (gasoline and/or 

diesel) are indistinguishable from 

products made from crude oil. Thus, 

rather than requiring the refiner to 

document what portion of the 

renewable crude-based fuel is renewable 

fuel, we are requiring that the volume of 

the renewable crude itself count as the 

volume of renewable fuel produced for 

the purposes of determining the volume 

block codes that are in the RIN 

(discussed in further detail in Section 

III.D).22 The general counting procedure 

for renewable crude-based fuels that are 

not derived through coprocessing with 

fossil fuels is that the volumes of 

renewable fuel produced are measured 

directly, and an appropriate 

Equivalence Value is assigned according 

to the methodology discussed in Section 

III.B.4. 

4. What Are ‘‘Equivalence Values’’ for 

Renewable Fuel? 

One question that EPA needed to 

address in developing the regulations 

was how to count volumes of renewable 

fuel in determining compliance with the 

renewable volume obligation. The Act 

stipulates that every gallon of wastederived ethanol and cellulosic biomass 

ethanol should count as if it were 2.5 

gallons for RFS compliance purposes. 

The Act does not stipulate similar 

values for other renewable fuels, but as 

described below we believe it is 

appropriate to do so. 

We are requiring that the 

‘‘Equivalence Values’’ for renewable 

fuels other than those for which specific 

values are set forth in the Act be based 

on their energy content in comparison 

to the energy content of ethanol, 

adjusted as necessary for their 

renewable content. The result is an 

Equivalence Value for corn ethanol of 

1.0, for biobutanol of 1.3, for biodiesel 

(mono alkyl ester) of 1.5, and for nonester renewable diesel of 1.7. However, 

the methodology can be used to 

determine the appropriate equivalence 

value for any other potential renewable 

fuel as well. 

This section describes why the use of 

the Equivalence Value approach in 

today’s rule is appropriate under the 

Act, and our conclusions regarding the 

possible future use of lifecycle analyses 

as the basis of Equivalence Values. 

a. Authority Under the Act To Establish 

Equivalence Values 

We are requiring that Equivalence 

Values be assigned to every renewable 

fuel to provide an indication of the 

number of gallons that can be claimed 

for compliance purposes for every 

physical gallon of renewable fuel. An 

Equivalence Value of 1.0 means that 

every physical gallon of renewable fuel 

counts as one gallon for RFS compliance 

purposes. An Equivalence Value greater 

than 1.0 means that every physical 

gallon of renewable fuel counts as more 

than one gallon for RFS compliance 


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Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 23919 

purposes, while a value less than 1.0 

counts as less than one gallon. 

We have interpreted the Act as 

allowing us to develop Equivalence 

Values according to the methodology 

discussed below. We believe that the 

use of Equivalence Values based on 

energy content in comparison to the 

energy content of ethanol is consistent 

with the intent of Congress to treat 

different renewable fuels differently in 

different circumstances, and to provide 

incentives for use of renewable fuels in 

certain circumstances, as evidenced by 

those specific circumstances addressed 

by Congress. The Act has several 

provisions that provide for mechanisms 

other than straight volume measurement 

to determine the value of a renewable 

fuel in terms of RFS compliance. For 

example, 1 gallon of cellulosic biomass 

or waste derived ethanol is to be treated 

as 2.5 gallons of renewable fuel. EPA is 

also required to establish an 

‘‘appropriate amount of credits’’ for 

biodiesel, and to provide for ‘‘an 

appropriate amount of credit’’ for using 

more renewable fuels than are required 

to meet your obligation. EPA is also to 

determine the ‘‘renewable fuel portion’’ 

of a blending component derived from 

a renewable fuel. These statutory 

provisions provide evidence that 

Congress did not limit this program 

solely to a straight volume measurement 

of gallons in the context of the RFS 

program. 

In response to the NPRM, some 

commenters supported our view that the 

Act provides sufficient context and 

direction to permit the use of 

Equivalence Values, while other 

commenters opposed this view. Some 

parties commented that the 

methodology proposed in the NPRM did 

not go far enough. These parties argued 

that instead of energy content, EPA 

should be using lifecycle impacts to set 

the Equivalence Values. Lifecycle 

analyses are discussed in more detail in 

Section III.B.4.c. 

Parties that opposed our proposed 

approach to Equivalence Values argued 

that since the Act did not explicitly give 

EPA the authority to set Equivalence 

Values for renewable fuels other than 

cellulosic biomass ethanol and wastederived ethanol, EPA had no authority 

to do so. In their view, the explicit 

inclusion of a 2.5 credit value for 

cellulosic and waste-derived ethanol 

and the omission of any credit values 

for other renewables fuels should be 

taken as evidence that Congress 

intended all other renewable fuels to 

have Equivalence Values of 1.0. 

We disagree that our discretion is so 

strictly limited. The Act specifically 

gave EPA the authority to determine an 

‘‘appropriate’’ credit for biodiesel, and 

also establishes a 2.5 value for cellulosic 

biomass ethanol and waste-derived 

ethanol. As ethanol and biodiesel were 

likely the two primary renewable fuels 

envisioned in the near-term under the 

Act, it would seem normal for Congress 

to have focused on these. However, 

Congress also clearly allowed for other 

renewable fuels to participate in the 

RFS program, and it is appropriate for 

EPA to consider how they should be 

treated under the Act. Furthermore, in 

addition to the Act’s direction that EPA 

determine an appropriate level of credit 

for biodiesel, the Act also directs EPA 

to determine the ‘‘appropriate’’ amount 

of credit for renewable fuel use in 

excess of the required volumes, and to 

determine the ‘‘renewable fuel portion’’ 

of a blending component derived from 

a renewable fuel. These statutory 

provisions lend further support to our 

belief that Congress did not limit the 

RFS program solely to a straight volume 

measurement of gallons. Having 

concluded that it is appropriate to 

determine an appropriate level of credit 

for biodiesel based on energy content as 

compared to ethanol, EPA is using a 

consistent approach for other types of 

renewable fuels for which a specific 

statutory credit value is not prescribed. 

Another reason given by parties 

opposing our approach to Equivalence 

Values was that Equivalence Values 

higher than 1.0 would result in actual 

volumes of renewable fuel being less 

than the volumes required by the Act. 

Although it is true that the Act specifies 

the annual volumes of renewable fuel 

that the program must require and 

directs EPA to promulgate regulations 

ensuring that gasoline sold each year 

‘‘contains the applicable volume of 

renewable fuel,’’ the Act also contains 

language that makes the achievement of 

those volumes imprecise. For instance, 

the deficit carryover provision allows 

any obligated party to fail to meet its 

RVO in one year if it meets the deficit 

and its RVO in the next year. If many 

obligated parties took advantage of this 

provision, it could result in the 

nationwide total volume obligation for a 

particular calendar year not being met. 

In addition, the calculation of the 

renewable fuel standard is based on 

projected nationwide gasoline volumes 

provided by EIA (see Section III.A). If 

the projected gasoline volume falls short 

of the actual gasoline volume in a given 

year, the standard will fail to create the 

demand for the full renewable fuel 

volume required by the Act for that 

year. The Act contains no provision for 

correcting for underestimated gasoline 

volumes, and as a result the volumes 

required by the Act may not be 

consumed in use. 

Some commenters disagreed with our 

belief that there will only be very 

limited additional situations where an 

Equivalence Value other than 1.0 is 

used. They expressed concern that the 

provision for Equivalence Values will 

interfere with meeting the total national 

volume goals for usage of renewable 

fuel. 

While in the long term we agree that 

renewable fuels with an Equivalence 

Value greater than 1.0 may grow to 

become a larger portion of the 

renewable fuel pool, we do not believe 

that this is likely to be the case before 

2013, the time period when the statute 

specifies the overall national volumes. 

EPA will be issuing a new rule prior to 

2013, and can reconsider its approach to 

Equivalence Values for renewable fuel 

at that time if it is appropriate to do so. 

For instance, EIA projects that biodiesel 

volumes will reach 300 million gallons 

by 2012. With the Equivalence Value of 

1.5 that we are finalizing today, this 

means that the 7.5 billion gallons 

required by the Act for 2012 could be 

met with 7.35 billion gallons of 

renewable fuel. However, this result is 

well within the variability in actual 

volumes resulting from the other 

statutory provisions described above, 

and would still result in 7.5 billon 

gallons of ethanol-equivalent (in terms 

of energy content) renewable fuel being 

consumed. Congress explicitly 

recognized the expected use of credits 

for biodiesel, as it did for cellulosic 

ethanol. By requiring or authorizing 

EPA to assign credit values for such 

products, Congress recognized that the 

national volumes specified in the Act 

would not necessarily be met on a 

gallon per gallon basis. For the very 

limited number of other renewable fuels 

not covered by these express statutory 

provisions, assigning an equivalence 

value is consistent with this overall 

approach. Moreover, EIA is projecting 

that the total volume of renewable fuel 

will exceed the Act’s requirements by a 

substantial margin due primarily to the 

favorable economics of ethanol in 

comparison to gasoline. Under such 

projections, the existence of renewable 

fuels with Equivalence Values higher 

than 1.0 will have no impact on the 

demand for renewable fuel. 

Finally, the Act also contains 

language indicating that EPA has 

flexibility in determining how various 

renewable fuels should count towards 

meeting the required annual volumes. 

For instance, valid renewable fuels are 

defined as those that ‘‘replace or reduce 

the quantity of fossil fuel present in a 

fuel mixture used to operate a motor 


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23920 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

23 ‘‘Calculation of equivalence values for 

renewable fuels under the RFS program’’, memo 

from David Korotney to EPA Air Docket OAR– 

2005–0161. 

vehicle.’’ Fossil fuels such as gasoline or 

diesel are only replaced or reduced to 

the degree that the energy they contain 

is replaced or reduced. We do not 

believe it would be appropriate to treat 

a renewable fuel with very low 

volumetric energy content as being 

equivalent to a renewable fuel with very 

high volumetric energy content, since 

the impact on motor vehicle fossil fuel 

use is very different for these two 

renewable fuels. The use of Equivalence 

Values based on volumetric energy 

content helps to achieve this goal. 

A case in point would be butanol. It 

is produced from the same feedstocks as 

ethanol (i.e., starch crops such as corn) 

in a similar process. However, it results 

in an alcohol with a higher volumetric 

energy content than ethanol. If we were 

to give butanol an Equivalence Value of 

1.0, it would provide an economic 

disincentive for corn to be used to 

produce butanol instead of ethanol. 

As a result, we continue to believe 

that the assignment of Equivalence 

Values other than 1.0 to some renewable 

fuels is a reasonable way for the RFS 

program to establish ‘‘appropriate’’ 

credit values while also ensuring that 

the Act’s volume obligations, read 

together with the Act’s directions 

regarding credit values towards 

fulfillment of that obligation, are 

satisfied. This approach is consistent 

with the way Congress treated the 

various specific circumstances noted 

above, and thus is basically a 

continuation of that process. 

b. Energy Content and Renewable 

Content as the Basis for Equivalence 

Values 

To appropriately account for the 

different energy contents of different 

renewable fuels as well as the fact that 

some renewable fuels actually contain 

some non-renewable content, we are 

requiring that Equivalence Values be 

calculated using both the renewable 

content of a renewable fuel and its 

energy content. This section describes 

the calculation methodology for 

Equivalence Values. 

In order to take the energy content of 

a renewable fuel into account when 

calculating the Equivalence Values, we 

must identify an appropriate point of 

reference. Ethanol is a reasonable point 

of reference as it is currently the most 

prominent renewable fuel in the 

transportation sector, and it is likely 

that the authors of the Act saw ethanol 

as the primary means through which the 

required volumes would be met in at 

least the first years of the RFS program. 

By comparing every renewable fuel to 

ethanol on an equivalent energy content 

basis, each renewable fuel is assigned an 

Equivalence Value that precisely 

accounts for the amount of petroleum in 

motor vehicle fuel that is reduced or 

replaced by that renewable fuel in 

comparison to ethanol. To the degree 

that corn-based ethanol continues to 

dominate the pool of renewable fuel, 

this approach allows actual volumes of 

renewable fuel to be consistent with the 

volumes required by the Act. 

Equivalence Values also account for 

the renewable content of renewable 

fuels, since the presence of any nonrenewable content impairs the ability of 

the renewable fuel to replace or reduce 

the quantity of fossil fuel present in a 

fuel mixture used to operate a motor 

vehicle. The Act specifically states that 

only the renewable fuel portion of a 

blending component should be 

considered part of the applicable 

volume under the RFS program. As 

described in more detail below, we have 

interpreted this to mean that every 

renewable fuel should be evaluated at 

the molecular level to distinguish 

between those molar fractions that were 

derived from a renewable feedstock, 

versus those molar fractions that were 

derived from a fossil fuel feedstock. 

Along with energy content in 

comparison to ethanol, the relative 

energy fraction of renewable versus nonrenewable content is thus used directly 

as the basis for the Equivalence Value. 

We are requiring that the calculation 

of Equivalence Values simultaneously 

take into account both the renewable 

content of a renewable fuel and its 

energy content in comparison to 

denatured ethanol. To accomplish this, 

we are requiring the following formula: 

EV = (RRF / REth) × (ECRF / ECEth) 

Where: 

EV = Equivalence Value for the renewable 

fuel. 

RRF= Renewable content of the renewable 

fuel, in percent of molecular energy. 

REth= Renewable content of denatured 

ethanol, in percent of molecular energy. 

ECRF= Energy content of the renewable fuel, 

in Btu per gallon (LHV). 

ECEth= Energy content of denatured ethanol, 

in Btu per gallon (LHV). 

Instead of the higher heating value, 

the lower heating value (LHV) is used to 

represent energy content because it 

more accurately reflects the energy 

available in the fuel to produce work. 

R is a measure of that portion of the 

renewable fuel molecules which can be 

considered to have come from a 

renewable source. Since R (that is, RRF

and REth) is being combined with 

relative energy content in the formula 

above, the value of R cannot be based 

on the weight fraction of the atoms in 

the molecule which came from a 

renewable feedstock (the ‘‘renewable 

atoms’’), but rather must be based on the 

energy inherent in that portion of the 

molecules comprised of renewable 

atoms. To identify the renewable atoms 

within the molecules that comprise the 

renewable fuel, we must examine the 

chemical process through which the 

renewable fuel was produced. A 

detailed explanation of calculations for 

R and several examples are given in a 

technical memorandum in the docket.23

In the case of ethanol, denaturants are 

added to preclude the ethanol’s use as 

food. Denaturants are generally a fossilfuel based, gasoline-like hydrocarbon in 

concentrations of 2–5 volume percent, 

with 5 percent being the most common 

historical level. One commenter argued 

that the Equivalence Value of ethanol 

must be specified as 0.95 for this very 

reason. However, as described in the 

NPRM, we believe that the Equivalence 

Value for ethanol should be specified as 

1.0 despite the presence of a denaturant. 

First, as stated above, ethanol is 

expected to dominate the renewable fuel 

pool for at least the next several years, 

and it is likely that the authors of the 

Act recognized this fact. Thus it seems 

likely that it was the intent of the 

authors of the Act that each physical 

gallon of denatured ethanol be counted 

as one gallon for RFS compliance 

purposes. Second, the accounting of 

ethanol has historically ignored the 

presence of the denaturant. For 

instance, under Internal Revenue 

Service (IRS) regulations the denaturant 

can be counted as ethanol by parties 

filing claims to the IRS for the federal 

excise tax credit. Also, EIA reporting 

requirements for ethanol producers 

allow them to include the denaturant in 

their reported volumes. The commenter 

arguing for the use of an Equivalence 

Value of 0.95 for ethanol provided no 

additional information to counter these 

arguments. 

Since we are requiring that denatured 

ethanol be assigned an Equivalence 

Value of 1.0, this must be reflected in 

the values of REth and ECEth. We have 

calculated these values to be 93.1 

percent and 77,550 Btu/gal, 

respectively. Details of these 

calculations can be found in the 

aforementioned technical memorandum 

to the docket. The final equation to be 

used for calculation of Equivalence 

Values is therefore: 

EV = (R / 0.931) * (EC / 77,550) 

Where: 

EV = Equivalence Value for the renewable 

fuel. 


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24The 2.5 value is specified by the Energy Act, 

and is not based on the EV formula discussed 

earlier. 

R = Renewable content of the renewable fuel, 

expressed as a percent, on an energy 

basis, of the renewable fuel that comes 

from a renewable feedstock. 

EC = Energy content of the renewable fuel, 

in Btu per gallon (lower heating value). 

For the specific case of biogas which 

cannot be measured in volumetric units, 

we are specifying that 77,550 Btu of 

biogas will be considered to be the 

equivalent of one gallon of renewable 

fuel. 

The calculation of the Equivalence 

Value for a particular renewable fuel 

can lead to values that deviate only 

slightly from 1.0, and/or can have 

varying degrees of precision depending 

on the uncertainty in the value of R or 

ECRF. In the NPRM we proposed several 

simplifications to streamline the 

application of Equivalence Values in the 

context of the RFS program. These 

included the use of pre-specified bins, 

rounding, and the use of an Equivalence 

Value of 1.0 when the calculated value 

was close to 1.0. We received some 

comments suggesting that these three 

simplifications unnecessarily 

complicated the determination of 

Equivalence Values. Based on 

comments received, we have 

determined for the final rule to simplify 

the application of Equivalence Values 

by only requiring the calculated values 

be rounded to the first decimal place. 

Also, based on consideration of 

comments received on how such 

products should be counted, for 

renewable diesel produced by 

processing fats and oils through a 

refinery hydrotreating process, we have 

determined that the default Equivalence 

Value should be 1.7 consistent with 

renewable diesel produced through 

other processes. This approach 

recognizes that hydrotreating produces a 

product consistent with our definition 

of non-ester renewable diesel. 

Furthermore, based on comments 

received, the volume of the final 

product is expected to be comparable to 

the volume of the input renewable 

crude. Therefore, the volume of 

renewable crude will be used as a 

surrogate for the volume of the final 

product. With the exception of 

renewable diesel produced through 

hydroteating fats or oils which is 

identical to renewable diesel, none of 

the specific Equivalence Values 

proposed in the NPRM have changed as 

a result of this simplification. The final 

values are shown in the table below. 

TABLE III.B.4–1.—EQUIVALENCE

VALUES FOR SOME RENEWABLE FUELS

Equivalence 

value 

(EV) 

Cellulosic biomass ethanol or 

waste-derived ethanol 24 ........... 2.5 

Ethanol from corn, starches, or 

sugar ......................................... 1.0 

Biodiesel (mono alkyl ester) ......... 1.5 

Non-ester renewable diesel and 

hydrotreated renewable crudes 1.7 

Butanol .......................................... 1.3 

Renewable crude-based fuels ...... 1.0 

Consistent with the NPRM, the 

Equivalence Value for renewable crudebased fuels is 1.0. Although some 

renewable crude-based fuels might 

warrant a higher value based on their 

energy content, it is also likely that 

some of the renewable crude does not 

end up as a motor vehicle fuel. Rather 

than requiring the refiner to document 

what portion of the biocrude-based 

renewable fuel is other than diesel or 

gasoline (e.g., jet fuel), we are 

combining the Equivalence Value of 1.0 

with a requirement that the volume of 

the renewable crude itself count as the 

volume of renewable fuel produced for 

the purposes of determining the volume 

block codes that are in the RIN 

(discussed in further detail in Section 

III.D). While this approach may result in 

some products such as jet fuel being 

counted as renewable fuel, we believe 

the majority of the products produced 

will be motor vehicle fuel because we 

assume refiners who elect to use 

biocrudes would do so to help meet the 

requirements of this rule. Furthermore, 

both diesel and gasoline presently make 

up about 85 percent of the product slate 

of refineries on average. This amount 

that has been steadily increasing for 

over time, and we expect that the 

percentage will continue to increase as 

demand for gasoline and diesel 

increases. Thus the designation of an 

Equivalence Value of 1.0 balances out 

the potentially higher energy content of 

renewable crude-based fuels with the 

potential for lower yields of renewable 

fuel produced as motor vehicle fuel. We 

received no comment on this issue and 

are finalizing it as proposed. 

Since there are a wide variety of 

possible renewable fuels that could 

qualify under the RFS program, there 

may be cases in which a party produces 

a renewable fuel not shown in Table 

III.B.4–1. A party may also produce a 

renewable fuel listed in the above table, 

but which has a different renewable 

content or energy content than the 

values assumed for our calculations. For 

such cases we have created a regulatory 

mechanism through which the producer 

may submit a petition to the Agency 

describing the renewable fuel, its 

feedstock and production process, and 

the calculation of its Equivalence Value. 

The Agency will review the petition and 

approve an appropriate Equivalence 

Value based on the information 

provided. We will publish newly 

assigned Equivalence Values in the 

Federal Register at the same time as the 

annual standard is published each 

November. 

In the NPRM, we also described an 

additional approach to setting the 

Equivalence Value for biodiesel (mono 

alkyl esters). Since ethanol derived from 

waste products such as animal wastes 

and municipal solid waste will be 

assigned an Equivalence Value of 2.5 

based on a requirement in the Act, we 

pointed out that it might be appropriate 

to create a parallel provision for 

biodiesel made from wastes. Under this 

approach, biodiesel made from waste 

products would have been assigned an 

Equivalence Value of 2.5 through 2012. 

Supporters of 2.5 Equivalence Value 

argued that it would place the treatment 

of waste-derived biodiesel on the same 

level as waste-derived ethanol, and that 

it would be good Agency policy to 

encourage and reward parties that turn 

materials that would otherwise be 

wasted into usable motor vehicle fuel. 

While some of these arguments may 

have merit, we nevertheless believe that 

it is most appropriate to maintain the 

general methodology applicable to 

renewable fuels at this time and reserve 

the 2.5:1 valuation for just the fuel 

specified by Congress. Therefore, we 

have not finalized a 2.5 Equivalence 

Value for waste-derived biodiesel. 

For the specific case of ETBE, we have 

chosen for this final rule to eliminate a 

uniquely determined Equivalence 

Value. As described in Section III.D.2.b, 

ETBE is generally made from ethanol to 

which RINs will have already been 

assigned. An ETBE producer, therefore, 

would need only assign the RINs 

received with the ethanol to the ETBE 

made from that ethanol. In this case, 

there will be no need to generate new 

RINs, and therefore no need for a 

separate Equivalence Value. 

Except for cellulosic biomass ethanol 

and waste-derived ethanol, the 

Equivalence Values shown in Table 

III.B.4–1, or any others approved 

through the petition process, will be 

applicable for all years. However, 

beginning in 2013, the 2.5 to 1 ratio no 

longer applies for cellulosic biomass 


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25CAA Section 211(o)(2)(A)(i), as added by 

Section 1501(a) of the Energy Policy Act of 2005. 

ethanol. The Act is unclear about 

whether the 2.5 to 1 ratio for wastederived ethanol will apply after 2012, 

though it might be appropriate to treat 

cellulosic biomass ethanol and wastederived ethanol in a consistent manner. 

Nevertheless, in the subsequent 

rulemaking mentioned above, we will 

address this issue explicitly. In today’s 

final rule we are only specifying the 

ratio for cellulosic biomass and wastederived ethanol prior to 2013. 

c. Lifecycle Analyses as the Basis for 

Equivalence Values 

In the NPRM we also described an 

alternative approach in which 

Equivalence Values for renewable fuels 

would be based on lifecycle analyses. 

We described both the merits and 

challenges associated with such an 

approach and requested comment. 

Based on the comments received we 

continue to believe that lifecycle 

analyses could provide a means of 

reflecting the relative benefits of one 

renewable fuel in comparison to 

another. However, we are not, in this 

action, establishing Equivalence Values 

on a lifecycle basis. Rather, we intend 

to continue evaluating and updating the 

tools and assumptions associated with 

lifecycle analyses in a collaborative 

effort with stakeholders. This 

rulemaking makes no determination and 

should not be interpreted to make any 

determination regarding whether EPA 

has the legal authority under section 

1501 of the Energy Act, as incorporated 

in section 211(o) of the Clean Air Act, 

to use lifecycle analysis in establishing 

Equivalence Values in general or 

Equivalence Values specifically related 

to greenhouse gas or carbon dioxide 

emissions. This section describes some 

of the comments we received on the use 

of lifecycle analyses and our responses. 

Lifecycle analyses involve an 

examination of fossil fuel used, and 

emissions generated, at all stages of a 

renewable fuel’s life. A typical lifecycle 

analysis examines production of the 

feedstock, its transport to a conversion 

facility, the conversion of the feedstock 

into renewable motor vehicle fuel, and 

the transport of the renewable fuel to 

the consumer. At each stage, every 

activity that consumes fossil fuels or 

results in emissions is quantified, and 

these energy consumption and emission 

estimates are then summed over all 

stages. By accounting for every activity 

associated with renewable fuels over 

their entire life, we can assess 

renewable fuels in terms of not just their 

impact within the transportation sector, 

but across all sectors and thus for the 

nation as a whole. In this way, lifecycle 

analyses provide a more complete 

picture of the potential impacts of 

different fuels or different fuel sources. 

While the use of energy content to 

establish Equivalence Values is an 

improvement over a simple gallon-forgallon approach, a lifecycle basis would 

provide a further level of sophistication 

in assessing the net energy input and 

output of fuels and the emissions 

associated with the use of different 

fuels. 

Supporters of the use of lifecycle 

analyses for setting the Equivalence 

Values of different renewable fuels 

pointed to several advantages of this 

approach. First, doing so could create an 

incentive for obligated parties to choose 

renewable fuels having a greater ability 

to reduce fossil fuel use or resulting 

emissions, since such renewable fuels 

would have higher Equivalence Values 

and thus greater value in terms of 

compliance with the RFS requirements. 

The preferential demand for renewable 

fuels having higher Equivalence Values 

could in turn spur additional growth in 

production of these renewable fuels. 

Second, using lifecycle analyses as the 

basis for Equivalence Values could 

orient the RFS program more explicitly 

towards reducing petroleum use, fossil 

fuel use or emissions. 

However, the use of lifecycle analyses 

to establish the Equivalence Values for 

different renewable fuels also raises a 

number of issues, generally 

acknowledged by supporters of the use 

of lifecycle analyses. For instance, 

lifecycle analyses can be conducted 

using several different metrics, 

including total fossil fuel consumed, 

petroleum energy consumed, regulated 

pollutant emissions (e.g., VOC, NOX, 

PM), carbon dioxide emissions, or 

greenhouse gas emissions. Each metric 

would result in a different set of 

Equivalence Values. At the present time 

there is no consensus on which metric 

would be most appropriate for this 

purpose or the purposes of the Act. 

There is also no consensus on the 

approach to lifecycle analyses 

themselves. Although we have chosen 

to base our lifecycle analyses on 

Argonne National Laboratory’s GREET 

model for the reasons described in 

Section IX, there are a variety of other 

lifecycle models and analyses available. 

The choice of model inputs and 

assumptions all have a bearing on the 

results of lifecycle analyses, and many 

of these assumptions remain the subject 

of debate among researchers. Lifecycle 

analyses must also contend with the fact 

that the inputs and assumptions 

generally represent industry-wide 

averages even though energy consumed 

and emissions generated vary widely 

from one facility or process to another. 

There currently exists no organized, 

comprehensive dialogue among 

stakeholders about the appropriate tools 

and assumptions behind any lifecycle 

analyses. We will be initiating more 

comprehensive discussions about 

lifecycle analyses with stakeholders in 

the near future. 

Another issue related to using 

lifecycle analyses as the basis for 

Equivalence Values pertains to the 

ultimate impact that the RFS program 

would have on petroleum use, fossil 

fuel use, regulated pollutant emissions, 

and/or emissions of GHGs. With a fixed 

volume of renewable fuel required 

under the RFS program, any renewable 

fuel with an Equivalence Value greater 

than 1.0 would necessarily mean that 

fewer actual gallons would be needed to 

meet the RFS standard. Thus, the 

advantage per gallon may be offset with 

fewer overall gallons, resulting in no 

overall additional benefit under the 

chosen metric for using fuels with 

higher Equivalence Values unless the 

RFS standard was simultaneously 

adjusted by Congress. 

Based on comments received in 

response to our NPRM, we continue to 

believe that the current state of 

scientific inquiry surrounding lifecycle 

analyses is not sufficiently robust to 

warrant its use to set Equivalence 

Values in this final rule. Since 

renewable fuel use is expected to far 

exceed the standards being finalized 

today, a higher equivalence value for 

those renewables with greater lifecycle 

benefits will likely do little to stimulate 

their use. However, if in the future the 

RFS standard more closely matches 

renewable demand, this could be 

important. We are committed to 

continuing our investigations into 

lifecycle analyses. 

C. What Gasoline Is Used To Calculate 

the Renewable Fuel Obligation and Who 

Is Required To Meet the Obligation? 

1. What Gasoline Is Used To Calculate 

the Volume of Renewable Fuel Required 

To Meet a Party’s Obligation? 

The Act requires EPA to promulgate 

regulations designed to ensure that 

‘‘gasoline sold or introduced into 

commerce in the United States (except 

in noncontiguous states or territories)’’ 

contains on an annual average basis, the 

applicable aggregate volumes of 

renewable fuels as prescribed in the 

Act.25 To implement this provision, 

today’s final rule provides that the 

volume of gasoline used to determined 

the renewable fuel obligation must 

include all finished gasoline (RFG and 


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26The noncontiguous states are Alaska and 

Hawaii. The territories are the Commonwealth of 

Puerto Rico, the U.S. Virgin Islands, Guam, 

American Samoa, and the Commonwealth of the 

Northern Marianas. 

27CAA Section 211(o)(3)(B), as added by Section 

1501(a) of the Energy Policy Act of 2005. 

conventional) produced or imported for 

use in the contiguous United States 

during the annual averaging period and 

all unfinished gasoline that becomes 

finished gasoline upon the addition of 

oxygenate blended downstream from 

the refinery or importer. This would 

include both unfinished reformulated 

gasoline, called ‘‘reformulated gasoline 

blendstock for oxygenate blending,’’ or 

‘‘RBOB,’’ and unfinished conventional 

gasoline designed for downstream 

oxygenate blending (e.g. sub-octane 

conventional gasoline), called ‘‘CBOB.’’ 

The volume of any other unfinished 

gasoline or blendstock, such as butane, 

is not included in the volume used to 

determine the renewable fuel obligation, 

except where the blendstock is 

combined with other blendstock or 

finished gasoline to produce finished 

gasoline, RBOB, or CBOB. Where a 

blendstock is blended with other 

blendstock to produce finished gasoline, 

RBOB, or CBOB, the total volume of the 

gasoline blend is included in the 

volume used to determine the 

renewable fuels obligation for the 

blender. Where a blendstock is added to 

finished gasoline, only the volume of 

the blendstock is included, since the 

finished gasoline would have been 

included in the compliance 

determinations of the refiner or importer 

of the gasoline. 

Gasoline produced or imported for 

use in a noncontiguous state or U.S. 

territory 26 is not included in the volume 

used to determine the renewable fuel 

obligation (unless the noncontiguous 

state or territory has opted-in to the RFS 

program), nor is gasoline, RBOB or 

CBOB exported for use outside the 

United States. 

For purposes of this preamble, the 

various gasoline products (as described 

above) that are included in the volume 

of gasoline used to determine the 

renewable fuel obligation are 

collectively called ‘‘gasoline.’’ 

The final rule excludes the volume of 

renewable fuels contained in gasoline 

from the volume of gasoline used to 

determine the renewable fuels 

obligation. In implementing the Act’s 

renewable fuels requirement, our 

primary goal was to design a program 

that is simple, flexible and enforceable. 

If the program were to include 

renewable fuels in the volume of 

gasoline used to determine the 

renewable fuel obligation, then every 

blender that blends ethanol downstream 

from the refinery or importer would be 

subject to the renewable fuel obligation 

for the volume of ethanol that they 

blend. There are currently 

approximately 1,200 such ethanol 

blenders. Of these blenders, only those 

who blend ethanol into RBOB are 

regulated parties under current fuels 

regulations. Designating all of these 

ethanol blenders as obligated parties 

under the RFS program would greatly 

expand the number of regulated parties 

and increase the complexity of the RFS 

program beyond that which is necessary 

to carry out the renewable fuels 

mandate under the Act. 

The Act provides that the renewable 

fuel obligation shall be ‘‘applicable to 

refiners, blenders, and importers, as 

appropriate.’’ 27 For the reasons 

discussed above, we believe it is 

appropriate to exclude downstream 

renewable fuel blenders from the group 

of parties subject to the renewable fuel 

obligation and to exclude renewable 

fuels from the volume of gasoline used 

to determine the renewable fuel 

obligation. This exclusion applies to any 

renewable fuels that are blended into 

gasoline at a refinery, contained in 

imported gasoline, or added at a 

downstream location. Thus, for 

example, any ethanol added to RBOB or 

CBOB downstream from the refinery or 

importer would be excluded from the 

volume of gasoline used to determine 

the obligation. Any non-renewable fuel 

added downstream, however, would be 

included in the volume of gasoline used 

to determine the obligation. This 

approach has no impact on the total 

volume of renewable fuels required 

(which is specified in the Act and must 

be met regardless of the approach taken 

here), but merely on the number of 

obligated parties. As discussed earlier, 

this volume of renewable fuel is 

likewise excluded from the calculation 

performed each year by EPA to 

determine the applicable percentage. 

The NPRM was unclear with regard to 

whether obligated parties are to 

determine their renewable fuel 

obligation based on the gasoline 

production of all of their facilities in the 

aggregate, or each facility individually. 

As discussed above, EPA has discretion 

under the Energy Act to determine the 

renewable fuels obligation applicable to 

parties, ‘‘as appropriate.’’ We believe 

that allowing obligated parties to 

determine their obligation based on 

either their facilities in the aggregate or 

individually is appropriate, since 

allowing this flexibility will not affect 

compliance with the RFS. Although 

some commenters expressed concern 

that obligated parties with multiple 

facilities could gain an economic 

advantage over obligated parties with 

only a single facility if aggregate 

compliance is allowed, we do not 

believe that this will be the case given 

the unrestricted trading allowed under 

our program. We also believe that 

clarification in the regulations regarding 

the basis on which the obligation may 

be determined is a necessary and logical 

outgrowth of the proposal. As a result, 

the regulations have been modified in 

the final rule to clarify that the 

renewable fuels obligation may be 

determined based on the gasoline 

production of all of an obligated party’s 

facilities in the aggregate, or each 

facility individually. 

We received comment that EPA 

should clarify when obligated parties 

must include imported gasoline that is 

used as ‘‘gasoline treated as 

blendstock’’, or GTAB, in the volume of 

gasoline used to determine the party’s 

renewable fuel obligation. As stated in 

the preamble to the proposed rule, 

GTAB is to be treated as a blendstock 

with regard to the RFS rule. Where the 

GTAB is blended with other blendstock 

(other than only renewable fuel) to 

produce gasoline, the total volume of 

the gasoline blend, including the GTAB, 

is included in the volume of gasoline 

used to determine the renewable fuel 

obligation. Where the GTAB is blended 

with finished gasoline, only the GTAB 

volume is included in the volume of 

gasoline used to determine the 

renewable fuel obligation (since the 

finished gasoline will already be 

included in the RFS calculations of the 

refiner of that gasoline). For purposes of 

compliance demonstrations, the RFS 

rule treats GTAB in a manner that is 

consistent with the reformulated 

gasoline (RFG) and conventional 

gasoline (CG) regulations. Under the 

RFG/CG regulations, importers who 

designate imported gasoline as GTAB 

must be registered with EPA as both an 

importer and a refiner. The importer 

submits separate compliance reports to 

EPA, one in its capacity as an importer, 

and one in its capacity as a refiner. The 

GTAB is blended by the importer and 

included in the importer’s compliance 

calculations in its capacity as a refiner 

of the GTAB, and is excluded from the 

importer’s compliance calculations in 

its capacity as an importer. The RFS 

rule treats GTAB in a similar manner; 

i.e., the importer includes the GTAB in 

the volume of gasoline used to 

determine the renewable fuel obligation 

of the importer in its capacity as a 

refiner of the GTAB, and excludes the 

GTAB in the volume of gasoline used to 


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28CAA Section 211(o)(a)(9), as added by Section 

1501(a) of the Energy Policy Act of 2005. 

determine the renewable fuel obligation 

of the importer in its capacity as an 

importer. The regulations have been 

clarified with regard to how GTAB is 

used to determine the GTAB importer’s 

renewable fuels obligation. 

We received comment that EPA 

should clarify that the terms RBOB and 

CBOB include ‘‘blendstocks for 

oxygenate blending’’ that are designed 

to comply with state fuels requirements, 

such as CARBOB (California), AZRBOB 

(Arizona), and LVBOB (Las Vegas). As 

discussed in Section III.C.1, all gasoline, 

and all unfinished gasoline that 

becomes finished gasoline upon the 

addition of oxygenate, that is produced 

or imported for use in the contiguous 

United States is included in the volume 

of gasoline used to determine an 

obligated party’s renewable fuels 

obligation. As such, any finished 

gasoline, or unfinished gasoline that 

becomes finished gasoline upon the 

addition of oxygenate, that is produced 

or imported to comply with state fuels 

programs must also be included in the 

volume of gasoline used to determine an 

obligated party’s renewable fuels 

obligation. The regulations have been 

clarified in this regard. 

2. Who Is Required To Meet the 

Renewable Fuels Obligation? 

Under the final rule, any person who 

meets the definition of refiner under the 

fuels regulations, which includes any 

blender who produces gasoline by 

combining blendstocks or blending 

blendstocks into finished gasoline, is 

subject to the renewable fuels 

obligation. Any person who brings 

gasoline into the 48 contiguous states 

from a foreign country or from an area 

that has not opted-in to the RFS 

program, or brings gasoline from a 

foreign country or an area that has not 

opted-in to the RFS program into an 

area that has opted-in to the RFS 

program, is considered an importer 

under the RFS program and is subject to 

the renewable fuels obligation. As noted 

above, a blender who only blends 

renewable fuels downstream from the 

refinery or importer is not subject to the 

renewable fuel obligation. Any person 

that is required to meet the renewable 

fuels obligation is called an ‘‘obligated 

party.’’ We generally refer to all of the 

obligated parties as refiners and 

importers, since the covered blenders 

are all refiners under the regulations. 

A refiner or importer located in a 

noncontiguous state or U.S. territory is 

not subject to the renewable fuel 

obligation and thus is not an obligated 

party (unless the noncontiguous state or 

territory opts-in to the RFS program). A 

party located within the contiguous 48 

states is an obligated party if it 

‘‘imports’’ into the 48 states any 

gasoline produced or imported by a 

refiner or importer located in a 

noncontiguous state or territory. 

We received comment that EPA 

should clarify how the RFS rule applies 

to transmix processors and blenders. 

Transmix processors and blenders are 

treated like any other blenders under 

the RFS rule. Transmix processors are 

parties that separate the gasoline portion 

of the transmix from the transmix and 

either sell the gasoline portion as 

finished gasoline or blend it with other 

components to produce gasoline. 

Transmix processors exclude the 

gasoline portion of the transmix from 

the volume that is used to determine the 

party’s renewable fuel obligation, since 

the gasoline portion of the transmix 

would have been included in the 

volume used to determine the 

renewable fuels obligation of the refiner 

or importer of the gasoline. In 

calculating the volume used to 

determine its renewable fuel obligation, 

the transmix processor would include 

any blendstocks (other than renewable 

fuels) that are added to the gasoline 

separated from the transmix. Where the 

transmix processor combines the 

gasoline portion of the transmix with 

purchased finished gasoline, both the 

gasoline portion of the transmix and the 

finished gasoline would be excluded, 

since the finished gasoline would have 

been included in the volume used to 

determine the renewable fuels 

obligation of the refiner or importer of 

the finished gasoline. Transmix 

blenders are parties that blend small 

amounts of unprocessed transmix into 

gasoline. Transmix blenders are not 

obligated parties if they only blend 

transmix into finished gasoline. If the 

transmix blender adds blendstocks to 

the transmix, the transmix blender 

would be an obligated party with regard 

to the volume of blendstocks added. The 

regulations have been clarified with 

regard to how the RFS rule applies to 

transmix processors and blenders. 

3. What Exemptions Are Available 

Under the RFS Program? 

a. Small Refinery and Small Refiner 

Exemption 

The Act provides an exemption from 

the RFS standard for small refineries 

during the first five years of the 

program. The Act defines small refinery 

as ‘‘a refinery for which the average 

aggregate daily crude oil throughput for 

a calendar year (as determined by 

dividing the aggregate throughput for 

the calendar year by the number of days 

in the calendar year) does not exceed 

75,000 barrels.’’ 28 Thus, any gasoline 

produced at a refinery that qualifies as 

a small refinery under this definition is 

not counted in determining the 

renewable fuel obligation of a refiner 

until January 1, 2011. Where a refiner 

complies with the renewable fuel 

obligation on an aggregate basis for 

multiple refineries, the refiner may 

exclude from its compliance 

calculations gasoline produced at any 

refinery that qualifies as a small refinery 

under the RFS program. This exemption 

applies to any refinery that meets the 

definition of small refinery stated above 

regardless of the size of the refining 

company that owns the refinery. Based 

on information currently available to us 

we expect 42 small refineries to qualify 

for this exemption. Beginning in 2011, 

small refineries will be required to meet 

the same renewable fuel obligation as all 

other refineries, unless their exemption 

is extended pursuant to § 80.1141(e). 

In addition to small refineries as 

defined in the Act, we proposed to 

extend this relief to refiners who, during 

2004: (1) Produced gasoline at a refinery 

by processing crude oil through refinery 

processing units; (2) employed an 

average of no more than 1,500 people, 

including all employees of the small 

refiner, any parent company and its 

subsidiary companies; and (3) had a 

total average crude oil processing 

capability for all of the small refiner’s 

refineries of 155,000 barrels per 

calendar day (bpcd). These size criteria 

were established in prior rulemakings 

and were the result of our analyses of 

small refiner impacts. Based on 

information currently available to us, 

we believe that there are only three 

gasoline refineries owned by small 

refiners that meet these criteria and that 

currently exceed the 75,000 bpcd crude 

oil processing capability defined by the 

Act. 

We received comments supporting the 

proposed extension of the small refinery 

exemption to small refiners, and we also 

received comments opposing the 

proposed provision. Commenters that 

supported the provision generally stated 

that they believe that a small refiner 

exemption is necessary as those entities 

(i.e., companies) that would qualify as 

small refiners are generally at an 

economic disadvantage due to their 

company size—whereas the Act only 

recognizes facilities, based on the size of 

each location. These commenters also 

stated that they have concerns with the 

cost and the availability of credits under 

this program, and believe that 

provisions for small refiners are 


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necessary to help mitigate any 

significant adverse economic impact on 

these entities. Commenters that opposed 

the provision stated that they believe 

that EPA exceeded its discretionary 

authority, that there appears to be no 

basis on which the Agency can 

legitimately expand this statutory 

exemption to add small refiners, and 

that Congress ‘‘clearly did not intend 

that the exemption be broadened to also 

include small refiners.’’ One commenter 

also stated that it does not believe that 

small refiner provisions are necessary 

because this rule does not require costly 

capital investments like previous fuel 

regulations. 

As stated in the proposal, we believe 

that we have discretion in determining 

an appropriate lead-time for the start-up 

of this program, as well as discretion to 

determine the regulated refiners, 

blenders and importers, ‘‘as 

appropriate.’’ We continue to believe 

that some refiners, due to their size, 

generally face greater challenges 

compared to larger refiners. The Small 

Business Regulatory Enforcement 

Fairness Act (SBREFA) also recognizes 

this and requires agencies, during 

promulgation of new standards, to 

assess the potential impacts on small 

businesses (as defined by the Small 

Business Administration (SBA) at 13 

CFR 121.201). For those instances where 

the Agency cannot certify that a rule 

will not have a significant economic 

impact on a substantial number of small 

entities, we are required to convene a 

SBREFA Panel. A SBREFA Panel 

process—which generally takes at least 

six months to complete—entails 

performing outreach with entities that 

meet the definition of a small business 

to develop ways to mitigate potential 

adverse economic impacts on small 

entities, in consultation with SBA and 

the Office of Management and Budget 

(OMB). 

‘‘Small refiners’’ have historically 

been recognized in EPA fuel regulations 

as those refiners who employ no more 

than 1,500 employees and have an 

average crude oil capacity of 155,000 

bpcd. These refiners generally have 

greater difficulty in raising and securing 

capital for investing in capital 

improvements and in competing for 

engineering resources and projects. This 

rulemaking does not require that 

refiners make capital improvements, 

however there are still significant costs 

associated with meeting the standard. 

While we were not required to assess 

the impacts on small businesses under 

the Energy Policy Act, we are required 

to do so under SBREFA. Based on our 

own analysis and outreach with small 

refiners, our assessment is that this rule 

will not impose a significant adverse 

economic impact on small refiners if 

they are given the small refinery 

exemption. Further, as noted above, we 

believe that no more than three 

additional refiners that do not meet the 

Energy Policy Act’s definition of a small 

refinery will qualify as small refiners for 

this rule. Therefore, we are finalizing 

the proposed provision that the small 

refinery exemption will be provided to 

qualified small refiners. This exemption 

does not mean that less renewable fuel 

will be used than is required in the 

Energy Policy Act; rather, it just means 

that small refiners will not be obligated 

to ensure that those volumes are 

attained during the period of their 

exemption. 

We also proposed to allow foreign 

refiners to apply for a small refinery or 

small refiner exemption under the RFS 

program. We requested comment on the 

provision and related aspects, and we 

received some comments in which 

commenters stated that they believe that 

there is no reason to extend the small 

refinery exemption to these refiners. 

One commenter even stated that it 

believes that such an allowance would 

be unlawful. We proposed this 

provision for consistency with prior 

gasoline-related fuel programs (antidumping, MSAT, and gasoline sulfur) 

which allowed foreign refiners to 

receive such exemptions, and we are 

finalizing the provision in this action. 

Under this provision, foreign small 

refiners and foreign small refineries can 

apply for an exemption from the RFS 

standards such that importers would not 

count the small refiner or small refinery 

gasoline volumes towards the importer’s 

renewable volume obligation. The 

Energy Policy Act does not prohibit EPA 

from granting this avenue of relief to 

foreign entities, and EPA believes it is 

consistent with the spirit of 

international trade agreements to 

provide it. 

In the proposal we stated that 

applications for a small refinery 

exemption must be received by EPA by 

September 1, 2007 for the exemption to 

be effective in 2007 and subsequent 

calendar years. We proposed that the 

application should include 

documentation that the small refinery’s 

average aggregate daily crude oil 

throughput for calendar year 2004 did 

not exceed 75,000 barrels; and that 

eligibility would be based on 2004 data 

(rather than 2005). Further, we proposed 

that the small refinery exemption would 

be effective 60 days after receipt of the 

application by EPA unless EPA notifies 

the applicant that the application was 

not approved or that additional 

documentation is required. We received 

comments on this provision in which 

commenters stated that requiring small 

refinery applications was inconsistent 

with the language set out in the Act. The 

commenters stated that small refineries 

should not be obligated parties in 2007 

even if they do not submit a small 

refinery application by September 1, 

2007. We agree with these statements, 

and believe that the Energy Policy Act 

did in fact intend to provide this 

exemption without the need for small 

refineries to submit applications. 

However, in order to ensure that this 

provision is not being misused, we 

believe that it is necessary for refiners 

to verify that their refineries meet the 

definition set out in the Act. Therefore, 

we are finalizing that the small refinery 

exemption will become active 

immediately upon the effective date of 

the rule. Refiners will only be required 

to send a letter to EPA verifying their 

status as a small refinery. We did not 

receive any comments on our proposal 

to base eligibility on 2004 data, nor did 

we receive comments on whether a 

multiple-year average should be used. 

We believe that eligibility should be 

based on 2004 data rather than on 2005 

data, since it was the first full year prior 

to passage of the Energy Act. In 

addition, some refineries’ production 

may have been affected by Hurricanes 

Katrina and Rita in 2005. We are thus 

finalizing our proposed approach to 

base eligibility on 2004 data. 

As discussed above, we proposed that 

refiners that do not qualify for a small 

refinery exemption under the 75,000 

bpcd criteria, but nevertheless meet the 

criteria of a small refiner may apply for 

small refiner status under the RFS rule. 

We proposed that the applications must 

be received by EPA by September 1, 

2007 for the exemption to be effective in 

2007 and subsequent calendar years 

(similar to the small refinery 

exemption). We also proposed that 

small refiner status would be 

determined based on documentation 

submitted in the application which 

demonstrates that the refiner met the 

criteria for small refiner status during 

the calendar year 2004 and that EPA 

would notify a refiner of approval or 

disapproval of small refiner status by 

letter. 

The final rule provides that qualified 

small refiners receiving the small 

refinery exemption will also receive the 

exemption immediately upon the 

effective date of the rule. These refiners 

must also submit a verification letter 

showing that they meet the small refiner 

criteria. This letter will be similar to the 

small refiner applications required 

under other EPA fuel programs (and 

must contain all the required elements 


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23926 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

specified in the regulations at 

§ 80.1142), except the letter will not be 

due prior to the program. Small refiner 

status verification letters for this rule 

that are later found to contain false or 

inaccurate information will be void as of 

the effective date of these regulations. 

Unlike the case for small refineries, 

small refiners who subsequently do not 

meet all of the criteria for small refiner 

status (i.e., cease producing gasoline by 

processing crude oil, employ more than 

1,500 people or exceed the 155,000 

bpcd crude oil capacity limit) as a result 

of a merger with or acquisition of or by 

another entity are disqualified as small 

refiners, except in the case of a merger 

between two previously approved small 

refiners. As in other EPA programs, 

where such disqualification occurs, the 

refiner must notify EPA in writing no 

later than 20 days following the 

disqualifying event. 

The Act provides that the Secretary of 

Energy must conduct a study for EPA to 

determine whether compliance with the 

renewable fuels requirement would 

impose a disproportionate economic 

hardship on small refineries. If the 

study finds that compliance with the 

renewable fuels requirements would 

impose a disproportionate economic 

hardship on a particular small refinery, 

EPA is required to extend the small 

refinery’s exemption for a period of not 

less than two additional years (i.e., to 

2013). The Act also provides that a 

refiner with a small refinery may at any 

time petition EPA for an extension of 

the exemption for the reason of 

disproportionate economic hardship. In 

accordance with these provisions of the 

Act, we are finalizing the provision that 

refiners with small refineries may 

petition EPA for an extension of the 

small refinery exemption. As provided 

in the Act, EPA will act on the petition 

not later than 90 days after the date of 

receipt of the petition. Today’s 

regulations do not provide a comparable 

opportunity for an extension of the 

small refinery exemption for small 

refiners. Therefore, all parties 

temporarily exempted from the RFS 

program on the basis of qualifying as a 

small refiner, rather than a small 

refinery, must comply with the program 

beginning January 1, 2011 (unless they 

waive their exemption prior to this 

date). 

During the initial exemption period 

for small refineries and small refiners 

and any extended exemption periods for 

small refineries, the gasoline produced 

by exempted small refineries and 

refineries owned by approved small 

refiners will not be subject to the 

renewable fuel standard. 

We proposed that the automatic 

exemption to 2011 and any small 

refinery extended exemptions may be 

waived upon notification to EPA; and 

we are finalizing this provision. 

Gasoline produced at a refinery which 

waives its exemption will be included 

in the RFS program and will be 

included in the gasoline used to 

determine the refiner’s renewable fuel 

obligation. If a refiner waives the 

exemption for its small refinery or its 

exemption as a small refiner, the refiner 

will be able to separate and transfer 

RINs like any other obligated party. If a 

refiner does not waive the exemption, 

the refiner could still separate and 

transfer RINs, but only for the renewable 

fuel that the refiner itself blends into 

gasoline (i.e. the refinery operates as an 

oxygenate blender facility). Thus, 

exempt small refineries and small 

refiners who blend ethanol can separate 

RINs from batches without opting in to 

the program in the same manner that an 

oxygenate blender is allowed to do. 

b. General Hardship Exemption 

In recent rulemakings, we have 

included a general hardship exemption 

for parties that are able to demonstrate 

severe economic hardship in complying 

with the standard. We proposed not to 

include provisions for a general 

hardship exemption in the RFS 

program. Unlike most other fuels 

programs, the RFS program includes 

inherent flexibility since compliance 

with the renewable fuels standard is 

based on a nationwide trading program, 

without any per gallon requirements, 

and without any requirement that the 

refiner or importer produce the 

renewable fuel. By purchasing RINs, 

obligated parties will be able to fulfill 

their renewable fuel obligation without 

having to make capital investments that 

may otherwise be necessary in order to 

blend renewable fuels into gasoline. We 

believe that sufficient RINs will be 

available and at reasonable prices, given 

that EIA projects that far greater 

renewable fuels will be used than 

required. Given the flexibility provided 

in the RIN trading program, including 

the provisions for deficit carry-over, and 

the fact that the standard is proportional 

to the volume of gasoline actually 

produced or imported, we continue to 

believe a general hardship exemption is 

not warranted. As a result, the final rule 

does not contain provisions for a general 

hardship exemption. 

c. Temporary Hardship Exemption 

Based on Unforeseen Circumstances 

In recent rulemakings, we have 

included a temporary hardship 

exemption based on unforeseen 

circumstances. We proposed not to 

include such an exemption in the RFS 

program. The need for such an 

exemption would primarily be based on 

the inability to comply with the 

renewable fuels standard due to a 

natural disaster, such as a hurricane. 

However, in the event of a natural 

disaster, we believe it is likely that the 

volume of gasoline produced by an 

obligated party would also drop, which 

would result in a reduction in the 

renewable fuel requirement. We, 

therefore, reasoned in the NPRM that 

unforeseen circumstances, such as a 

hurricane or other natural disaster, 

would not result in a party’s inability to 

obtain sufficient RINs to comply with 

the applicable renewable fuels standard. 

We received several comments 

regarding the inclusion of a temporary 

hardship exemption based on 

unforeseen circumstances. One 

commenter believes it would be of value 

to have a mechanism for selectively 

waiving or modifying the RFS 

downward on a temporary basis in the 

event of unforeseen circumstances such 

as significant drought affecting potential 

crop production. The commenter 

believes that crop shortages could have 

an impact on a national level, or a major 

disaster may impact logistics of 

renewable fuel distribution regionally, 

necessitating a more rapid response 

from EPA than is provided in the Energy 

Act. Another commenter believes that a 

temporary hardship exemption based on 

unforeseen circumstances should be 

included in the rule since it is 

impossible to predict how the RFS 

program will impact small refiners. 

Another commenter believes that, given 

the variety of potentially challenging 

unforeseen events during the last 

several years, it is not inconceivable that 

man-made or natural circumstances 

could adversely impact the RFS 

program. A natural disaster in the 

agricultural section, for example, may 

make it difficult to meet the renewable 

fuels mandate which, in turn, could 

drive the price of RINs high enough to 

disrupt the gasoline market. The 

commenter believes that a mechanism 

built into the program from the outset 

would provide a more flexible and less 

disruptive way to address unforeseen 

circumstances than the more timeconsuming waiver process provided in 

the Energy Act. 

Under other EPA fuels programs, 

compliance is based on a demonstration 

that the fuel meets certain component or 

emissions standards. Unforeseen 

circumstances, such as a natural 

disaster, may affect an individual 

refiner’s or importer’s ability to produce 

or import fuel that complies with the 


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Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 23927 

29CAA section 211(o)(7), as added by Section 

1501(a) of the Energy Policy Act of 2005. 

30CAA Section 211(o)(2)(A)(ii), as added by 

Section 1501(a) of the Energy Policy Act of 2005. 

standards. As a result, we have included 

in other fuels programs provisions for a 

temporary hardship exemption from the 

standards in the event of an unforeseen 

natural disaster that affects a party’s 

ability to produce gasoline that 

complies with the standards. Unlike 

most other fuels programs, compliance 

under the RFS program is based on a 

demonstration that a party has fulfilled 

its individual renewable fuels obligation 

on an annual basis, as compared to 

meeting specific gasoline content 

requirements. The renewable fuels 

obligation can be met through the use of 

purchased RINs, and there is a deficit 

carry forward provision allowing 

compliance to be shown over more than 

one year. In the event of a natural 

disaster, the volume of gasoline 

produced by an obligated party is also 

likely to drop, which would result in a 

reduction in the party’s renewable fuel 

obligation. As a result, we believe that 

an individual party would be able to 

meet its renewable fuel obligation even 

in the event of a natural disaster that 

affects the party’s refinery or blending 

facility. Therefore, unlike other fuels 

programs, we do not believe there is a 

need to include a temporary hardship 

exemption in the RFS rule to address an 

individual party’s inability to comply 

with its renewable fuels obligation due 

to unforeseen circumstances. 

Most of the concerns raised by the 

commenters relate to problems that 

would have a more regional or national 

effect, as compared to affecting one or 

a few individuals. In the event that 

unforeseen circumstances do occur 

which result in a shortage of renewable 

fuel and available RINs, we believe that 

Congress provided an adequate 

mechanism for addressing such 

situations in the Energy Act.29 The 

Energy Act provides that on petition by 

one or more States, EPA, in consultation 

with the Departments of Agriculture and 

Energy, may waive the required 

aggregate renewable fuels volume 

obligation in whole or in part upon a 

sufficient showing of economic or 

environmental harm, or inadequate 

supply. As a result, we believe that a 

renewable fuel supply problem that 

affects all parties can be addressed using 

this statutory provision. We have 

carefully considered the comments; 

however, we do not believe that the 

comments provide a compelling 

rationale for providing a temporary 

hardship exemption from the RFS 

obligation based on unusual 

circumstances that goes beyond the 

provisions that Congress included in the 

Energy Act. As a result, the final rule 

does not contain provisions for a 

temporary hardship exemption based on 

unforeseen circumstances. 

4. What Are the Opt-in and State Waiver 

Provisions Under the RFS Program? 

a. Opt-in Provisions for Noncontiguous 

States and Territories 

The Act provides that, upon the 

petition of a noncontiguous state or U.S. 

territory, EPA may apply the renewable 

fuels requirements to gasoline produced 

in or imported into that noncontiguous 

state or U.S. territory at the same time 

as, or any time after the promulgation of 

regulations establishing the RFS 

program.30 In granting such a petition, 

EPA may issue or revise the RFS 

regulations, establish applicable volume 

percentages, provide for generation of 

credits, and take other actions as 

necessary to allow for the application of 

the RFS program in a noncontiguous 

state or territory. We believe that 

approval of the petition does not require 

a showing other than a request by the 

Governor of the State or the equivalent 

official of a Territory to be included in 

the program. 

Today’s final rule will implement this 

provision of the Act by providing a 

process whereby the governor of a 

noncontiguous state or territory may 

petition EPA to have the state or 

territory included in the RFS program. 

The petition must be received by EPA 

on or before November 1 for the 

noncontiguous state or territory to be 

included in the RFS program in the next 

calendar year. A noncontiguous state or 

territory for which a petition is received 

after November 1 would not be included 

in the RFS program in the next calendar 

year, but would be included in the RFS 

program in the subsequent year. For 

example, if EPA receives a petition on 

September 1, 2007, the noncontiguous 

state or territory would be included in 

the RFS program beginning on January 

1, 2008. If EPA receives a petition on 

December 1, 2007, the noncontiguous 

state or territory would be included in 

the RFS program beginning January 1, 

2009. We believe that requiring 

petitions to be received by November 1 

is necessary to allow EPA time to make 

any adjustments in the applicable 

standard. The method for calculating 

the renewable fuels standard to reflect 

the addition of a state or territory that 

has opted into the RFS program is 

discussed in Section III.A. Because 

today’s regulations make EPA approval 

of an opt-in petition automatic if it is 

signed by the appropriate authority and 

properly delivered to EPA, EPA does 

not envision providing an opportunity 

to comment on an opt-in request, 

although we will provide notice in the 

publication of the standard for the 

following year. 

We received several comments 

regarding when a noncontiguous state or 

territory should be able to opt-in to the 

RFS program. One commenter 

supported the approach in this final rule 

that EPA use the EIA Short-term Energy 

Outlook published each October to 

assist in determining the percentage 

standard and therefore a state can only 

opt-in beginning with the first full 

compliance period of 2008. Another 

commenter believed we should include 

a provision to allow noncontiguous 

states or territories to opt-in to the first 

compliance period which starts 

September 1, 2007. While we see the 

merits of allowing a noncontiguous state 

or territory to opt-in to the first 

compliance period, we intend to 

maintain the current approach and 

allow noncontiguous states and 

territories to opt-in beginning with the 

2008 compliance year. The statute 

clearly states that the program may 

apply to noncontiguous states and 

territories (that have petitioned EPA) at 

any time after these regulations have 

been promulgated. Given the short 

period of time between publication of 

the final rule and the effective date of 

the program, the need for a state and 

regulated parties to discuss opting-in 

with knowledge of the final version of 

the rule, and the requirement for EPA to 

notify obligated parties with sufficient 

lead time to any change in the standard, 

EPA believes 2008 is the earliest 

practical date for an opt-in to be 

effective. In addition, EPA notes that 

none of the noncontiguous states or 

territories indicated a strong interest in 

opting-in for the remainder of the 2007 

compliance period. 

Where a noncontiguous state or 

territory opts-in to the RFS program, 

producers and importers of gasoline for 

that state or territory will be obligated 

parties subject to the renewable fuel 

requirements. All refiners and importers 

who produce or import gasoline for use 

in a state or territory that has opted-in 

to the RFS program will be required to 

comply with the renewable fuel 

standard and will be able to separate 

RINs from batches of renewable fuels in 

the same manner as other obligated 

parties. 

Once a petition to opt-in to the RFS 

program is approved by EPA, the state 

or territory would remain in the RFS 

program and be treated as any of the 48 

contiguous states. We received a 

comment asserting that once a state or 


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23928 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

31CAA Section 211(o)(7), as added by Section 

1501(a) of the Energy Policy Act of 2005. 

32CAA Section 211(o)(2)(iii), as added by Section 

1501(a) of the Energy Policy Act of 2005. 

33CAA Section 211(o)(7), as added by Section 

1501(a) of the Energy Policy Act of 2005. 

territory opts-in, they should be 

required to remain in the program for at 

least 5 years. As stated earlier, EPA will 

recognize a state or territory that optsin to the program as identical to any of 

the 48 states. The current regulations do 

not allow a state to opt-out and the only 

form of relief from the program is a 

waiver, in whole or in part, of the 

national renewable fuel volume 

requirement. Noncontiguous states and 

territories should be aware of the 

obligations of the program and should 

only choose to opt-in if they expect to 

meet those obligations for the indefinite 

future. If in the future a state believes 

EPA should change its regulations and 

allow an opt-out the state could petition 

EPA to change the regulations. As in 

other situations where a party petitions 

EPA to revise its regulations, EPA 

would be in a position at that point to 

consider the concerns raised by the state 

as well as other interested stakeholder 

and to determine whether it would be 

appropriate to revise the regulations. 

b. State Waiver Provisions 

The Energy Act provides that EPA, in 

consultation with the U.S. Department 

of Agriculture (USDA) and the 

Department of Energy (DOE), may waive 

the renewable fuels requirements in 

whole or in part upon a petition by one 

or more states by reducing the national 

quantity of renewable fuel required 

under the Act.31 The Act also outlines 

the basic requirements for such a 

waiver, such as a demonstration that 

implementation of the renewable fuels 

requirements would severely harm the 

economy or environment of a state, a 

region, or the United States or that there 

is an inadequate domestic supply of 

renewable fuel. 

If EPA, after public notice and 

opportunity for comment, approves a 

state’s petition for a waiver of the RFS 

program, the Act stipulates that the 

national quantity of renewable fuel 

required (Table I.B–1) may be reduced 

in whole or in part. This reduction 

could reduce the percentage standard 

applicable to all obligated parties. 

However, there is no provision in the 

Act that would permit EPA to reduce or 

eliminate any obligations under the RFS 

program specifically for parties located 

within the state that petitioned for the 

waiver. Thus all refiners, importers, and 

blenders located in the state would still 

be obligated parties if they produce 

gasoline. In addition, an approval of a 

state’s petition for a waiver may not 

have any impact on renewable fuel use 

in that state since it would not be a 

prohibition on the sale or consumption 

of renewable fuels in that state. In fact, 

the Act prohibits the regulations from 

restricting the geographic areas in which 

renewable fuels may be used.32

Renewable fuel use in the state in 

question would thus continue to be 

driven by natural market forces and, 

perhaps if the economics of ethanol 

blending were less favorable than today, 

the nationally-applicable renewable fuel 

standard. 

Given that state petitions for a waiver 

of the RFS program appear unlikely to 

affect renewable fuel use in that state, 

we have not finalized regulations 

providing more specificity regarding the 

criteria for a waiver or the ramifications 

of Agency approval of such a waiver in 

terms of the level or applicability of the 

standard. However, states can still 

submit petitions to the Agency for a 

waiver of the RFS requirements under 

the provision in the Energy Act and 

such petitions will be addressed by EPA 

on a case-by-case basis. 

We received several comments 

objecting to the decision to not propose 

regulations detailing the waiver process 

and our rationale for not doing so. One 

commenter stated that nothing in the 

statute prevents relief from being 

directed toward a state which has 

requested the waiver by reducing the 

renewable fuel obligation of refiners, 

blenders, and importers who market 

gasoline in the affected state. Contrary 

to the commenter’s assertion, the statute 

states that, ‘‘[t]he Administrator * * * 

may waive the requirements * * * by 

reducing the national quantity of 

renewable fuel required’’.33 Congress’s 

clear intent was to limit EPA’s authority 

to provide relief under the state waiver 

provision of section 211(o)(7). Relief 

under that provision is limited to 

reducing the total national volume 

required under the RFS program. Thus, 

the renewable volume obligation for 

regulated parties would be reduced, but 

the reduced obligation would still apply 

to all obligated refiners, blenders and 

importers, including those in the state 

that requested the waiver. This may 

provide some relief to the part of the 

country submitting the petition, but 

EPA is not authorized to grant other 

more targeted relief such as reducing the 

percentage for some refiners and not 

others or refusing to count towards 

compliance renewable fuel that is 

produced or used in certain parts of the 

country. It should be noted here that 

this approach holds true for states or 

territories which have opted-in to the 

program as well. Once a state or 

territory has opted-in to the program, 

they will be treated as identical to any 

other state and specific relief will not be 

provided to regulated parties serving 

these areas after the approval of a 

waiver. Noncontiguous states and 

territories should consider this in 

discussions with regulated parties 

before opting-in to the program. 

Another commenter stated that EPA 

should publish regulations outlining 

specific criteria that will be considered 

in reviewing a petition, so that the 

public would have a more meaningful 

opportunity to participate in the 

process. While EPA realizes that the 

criteria provided by the statute are quite 

general, the rationales of severe 

environmental or economic harm or 

inadequate domestic supply are 

sufficient for a basic framework upon 

which a petition can be built and 

evaluated. Each situation in which a 

waiver may be requested will be unique, 

and promulgating a list of more specific 

criteria in the abstract may be counterproductive. Communication between 

the petitioning state(s), EPA, DOE, 

USDA, and public and industry 

stakeholders should begin early in the 

process, well before a waiver request is 

submitted. This communication will 

supply these federal agencies with a 

knowledgeable background of the 

situation prompting the potential waiver 

request. The waiver request may even 

prove unnecessary after an initial 

investigation and analysis of the 

situation. If not, and if the state 

continues to believe that a valid basis 

for submission of a petition exists, 

federal agencies can instruct the state(s) 

as to what more detailed information is 

needed for waiver approval. Petitions 

will be published in the Federal 

Register, as required by statute, to 

provide public notice and opportunity 

for comment. 

A third commenter raised the point 

that there is no provision in the Act that 

would permit EPA to waive any 

obligations for specific entities in a state 

that has petitioned for a waiver, and in 

the case of an emergency, such as a 

natural disaster, specific relief may be 

warranted. The commenter is correct in 

the observation that EPA cannot waive 

obligations for specific entities or 

locations. However, the Act does 

authorize EPA to waive the obligations 

of the program as it applies to all 

obligated parties, in whole or in part, 

depending on the severity of the 

situation. 


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34Those blenders who add ethanol to RBOB are 

already regulated under our reformulated gasoline 

regulations. 

D. How Do Obligated Parties Comply 

With the Standard? 

Under the Act, EPA is to establish a 

renewable fuel standard annually, 

expressed as a percentage of gasoline 

sold or introduced into commerce, that 

will ensure that overall a specified total 

national volume of renewable fuels will 

be used in gasoline in the U.S. The Act 

does not require each obligated party to 

necessarily do the blending themselves 

in order to comply with this obligation. 

Rather, under the credit trading program 

required by the Act, each obligated 

party is allowed to satisfy its obligations 

either through its own actions or 

through the transfer of credits from 

others who have more than satisfied 

their individual requirements. 

This section describes our final 

compliance program. It is based on the 

use of unique renewable identification 

numbers (RINs) assigned to batches of 

renewable fuel by renewable fuel 

producers and importers. These RINs 

can then be sold or traded, and 

ultimately used by any obligated party 

to demonstrate compliance with the 

applicable standard. Excess RINs serve 

the function of the credits envisioned by 

the Act and also provide additional 

benefits, as described below. We believe 

that our approach is consistent with the 

language and intent of the Act and 

preserves the natural market forces and 

blending practices that will keep 

renewable fuel costs to a minimum. 

1. Why Use Renewable Identification 

Numbers? 

Once renewable fuels are produced or 

imported, there is very high confidence 

that all but de minimus quantities will 

in fact be blended into gasoline or 

otherwise used as motor vehicle fuels, 

except for exports. Renewable fuels are 

not used for food, chemicals, or as 

feedstocks to other production 

processes. In fact the denaturant that 

must be added to ethanol is designed 

specifically to ensure that the ethanol is 

primarily used as motor vehicle fuel. In 

discussions with stakeholders prior to 

release of the NPRM, it became clear 

that other renewable fuels, including 

biodiesel and renewable fuels used in 

their neat (unblended) form, likewise 

are not used in appreciable quantities 

for anything other than motor vehicle 

fuel. Therefore if a refiner ensures that 

a certain volume of renewable fuel has 

been produced, in effect they have also 

ensured that this volume will be 

blended into gasoline or otherwise used 

as a motor vehicle fuel. Focusing on 

production of renewable fuel as a 

surrogate for use of such fuel has many 

benefits as far as streamlining the 

program and minimizing the influence 

that the program has on the operation of 

the market. 

In order to implement a program that 

is based on production of a certain 

volume of renewable fuels, we are 

finalizing a system of volume 

accounting and tracking of renewable 

fuels. We are requiring that this system 

be based on the assignment of unique 

numbers to each batch of renewable 

fuel. These numbers are called 

Renewable Identification Numbers or 

RINs, and are assigned to each batch by 

the renewable fuel producer or 

importer. 

The use of RINs allows the Agency to 

measure and track renewable fuel 

volumes starting at the point of their 

production rather than at the point 

when they are blended into 

conventional fuels. Although an 

alternative approach would be to 

measure renewable fuel volumes as they 

are blended into conventional gasoline 

or diesel, measuring renewable fuel 

volumes at the point of production 

provides more accurate measurements 

that can be easily verified. For instance, 

ethanol producers are already required 

to report their production volumes to 

EIA through Monthly Oxygenate 

Reports. These data provide an 

independent source for verifying 

volumes. The total number of batches 

and parties involved are also minimized 

in this approach. The total number of 

batches is smallest at the point of 

production, since batches are commonly 

split into smaller ones as they proceed 

through the distribution system to the 

place where they are blended into 

conventional fuel. The number of 

renewable fuel producers is also far 

smaller than the number of blenders. 

Currently there just over 100 ethanol 

plants and 85 biodiesel plants in the 

U.S., compared with approximately 

1200 blenders 34 based on IRS data. 

The assignment of RINs to batches of 

renewable fuel at the point of their 

production also allows those batches to 

be identified according to various 

categories important for compliance 

purposes. For instance, the RIN will 

contain a component that specifies 

whether a batch of ethanol was made 

from cellulosic feedstocks. This RIN 

component will be of particular 

importance for 2013 and beyond when 

the Act specifies a national volume 

requirement for cellulosic biomass 

ethanol. The RIN will also identify the 

Equivalence Value of the renewable fuel 

which will often only be known at the 

point of its production. Finally, the RIN 

will identify the year in which the batch 

was produced, a critical element in 

determining the applicable time period 

within which RINs are valid for 

compliance purposes. 

Although production volumes of 

renewable fuels intended for blending 

into gasoline are a reasonably accurate 

surrogate for volumes ultimately 

blended into gasoline, changes can 

occur at various times throughout the 

year in the volumes of renewable fuel 

that are in storage. These stock changes 

involve the temporary storage of 

renewable fuel during times of excess 

and can affect the length of time 

between production and ultimate use. 

While there may be seasonal 

fluctuations in stocks due to seasonal 

demand, these stock changes always 

have a net change of zero over the long 

term since there is no economic benefit 

to stockpiling renewable fuels. As a 

result there is no need to account for 

stock changes in our program. 

Exports of renewable fuel represent 

the only significant distribution 

pathway that could impair the use of 

production as a surrogate for renewable 

fuel blending into gasoline or other use 

as a motor vehicle fuel. However, our 

approach accounts for exports through 

an explicit requirement placed upon 

exporters (discussed in Section III.D.4 

below). As a result, we are confident 

that our approach satisfies the statutory 

obligation that our regulations impose 

obligations on refiners and importers 

that will ensure that gasoline sold or 

introduced into commerce in the U.S. 

each year will contain the volumes of 

renewable fuel specified in the Act. By 

tracking the amount of renewable fuel 

produced or imported and subtracting 

the amount exported, we will have an 

accurate accounting of the renewable 

fuel actually consumed as motor vehicle 

fuel in the U.S. Exports of renewable 

fuel are discussed in more detail in 

Section III.D.4. 

a. RINs Serve the Purpose of a Credit 

Trading Program 

According to the Act, we must 

promulgate regulations that include 

provisions for a credit trading program. 

The credit trading program allows a 

refiner that overcomplied with its 

annual RVO to generate credits 

representing the excess renewable fuel. 

The Act stipulates that those credits can 

then be used within the ensuing 12 

month period, or transferred to another 

refiner that had not blended sufficient 

renewable fuel into its gasoline to 

satisfy its RVO. In this way the credit 

trading program permits current 

blending practices to continue wherein 


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some refiners purchase a significant 

amount of renewable fuel for blending 

into their gasoline while others do little 

or none, thus providing a means for all 

refiners to economically comply with 

the standard. 

Our RIN-based program fulfills all the 

functions of a credit trading program 

and thus meets the Act’s requirements. 

If at the end of a compliance period a 

party had more RINs than it needed to 

show compliance with its renewable 

volume obligation, these excess RINs 

would serve the function of credits and 

could be used or traded in the next 

compliance period. RINs can be 

transferred to another party in an 

identical fashion to a credit. However, 

our program provides additional 

flexibility in that it permits all RINs to 

be transferred between parties before 

they are deemed to be in excess of a 

party’s annual RVO at the end of the 

year. This is because a RIN serves two 

functions: It is direct evidence of 

compliance and, after a compliance year 

is over, excess RINs serve the function 

of credits for overcompliance. Thus the 

RIN approach has the advantage of 

allowing real-time trading without 

having to wait until the end of the year 

to determine excess. 

As in other motor vehicle fuels credit 

programs, we are also requiring that any 

renewable producer that generates RINs 

must use an independent auditor to 

conduct annual reviews of the party’s 

renewable production, RIN generation, 

and RIN transactions. These reviews are 

called ‘‘attest engagements,’’ because the 

auditor is asked to attest to the validity 

of the regulated party’s credit 

transactions. For example, the 

reformulated gasoline program requires 

attest engagements for refiners and 

importers, and downstream oxygenate 

blenders to verify the underlying 

documentation forming the basis of the 

required reports (40 CFR part 80, 

subpart F). In the case of RIN 

generation, the auditor is required to 

verify that the number of RINs generated 

matched the volume of renewable fuels 

produced, that any extra value RINs are 

appropriately generated, and that RIN 

numbers are properly transferred with 

the renewable fuel as required by the 

regulations. 

b. Alternative Approach to Tracking 

Batches 

If we had not implemented a RINbased system for uniquely identifying, 

measuring, and tracking batches of 

renewable fuel, the RFS program would 

necessarily require that we measure 

renewable fuel volumes at the point in 

the distribution system where they are 

actually blended into conventional 

gasoline or diesel or used in their neat 

form as motor vehicle fuel. The NPRM 

described a number of significant 

problems that this approach would 

create, including the potential for 

double-counting, increasing the number 

of parties subject to enforcement 

provisions, and the loss of a distinction 

between cellulosic ethanol and other 

forms of ethanol. We concluded that a 

blender-based approach to tracking 

volumes of renewable fuel was inferior 

to our proposed program focusing on 

the point of production and 

importation. We did not receive any 

comments supporting a blender-based 

approach and, consistent with the 

rationale provided in the proposed rule, 

have decided not to implement it. 

2. Generating RINs and Assigning Them 

to Batches 

a. Form of Renewable Identification 

Numbers 

Each RIN is generated by the producer 

or importer of the renewable fuel and 

uniquely identifies not only a specific 

batch, but also every gallon in that 

batch. The RIN consists of a 38- 

character code having the following 

form: 

RIN: KYYYYCCCCFFFFFBBBBBRRD

SSSSSSSSEEEEEEEE 

Where: 

K = Code distinguishing assigned RINs from 

separated RINs. 

YYYY = Calendar year of production or 

import. 

CCCC = Company ID. 

FFFFF = Facility ID. 

BBBBB = Batch number. 

RR = Code identifying the Equivalence Value. 

D = Code identifying cellulosic biomass 

ethanol. 

SSSSSSSS = Start of RIN block. 

EEEEEEEE = End of RIN block. 

In response to the NPRM, one 

commenter requested that the full RIN 

generation date, not just the year, be 

included in the RIN. We believe that 

this is unnecessary and would unduly 

lengthen the RIN. Compliance with the 

standard is determined on a calendar 

year basis, and the year of RIN 

generation is necessary in order to 

ensure that RINs are used for 

compliance purposes only in the 

calendar year generated or the following 

year. See Section III.D.3.b. The full RIN 

generation date, while a potentially 

useful piece of information in the 

context of potential enforcement 

activities, is not necessary as a 

component of the RIN since 

recordkeeping requirements contain this 

same information and can be consulted 

in the enforcement context. 

The company and facility IDs are 

assigned by the EPA as part of the 

registration process as described in 

Section IV.B. Company IDs will be used 

primarily to determine compliance, 

while the inclusion of facility IDs allows 

the assignment of batch numbers unique 

to each facility. The use of both 

company and facility IDs is also 

consistent with our approach in other 

fuel programs. The batch number is 

chosen by the producer and includes 

five digits to allow for facilities that 

produce up to a hundred thousand 

batches per year. In the NPRM we 

proposed that batch numbers be 

sequential values starting with 00001 at 

the beginning of each year. Following 

release of the NPRM, some stakeholders 

expressed the desire to be able to align 

RIN batch numbers with numbers used 

in other aspects of their business. As a 

result, we have determined that the 

requirement that the batch numbers be 

sequential is not necessary so long as 

each batch number is unique within a 

given calendar year. Batches are 

described more fully in Section III.E.1.a. 

The RR, D, and K codes together 

describe the nature of the renewable 

fuel and the RINs that are generated to 

represent it. The RR code simply 

represents the Equivalence Value for the 

renewable fuel, multiplied by 10 to 

eliminate the decimal place inherent in 

Equivalence Values. Equivalence Values 

form the basis for the total number of 

RINs that can be generated for a given 

volume of renewable fuel, and are 

described in Section III.B.4. 

The D code identifies cellulosic 

biomass ethanol batches as such. Since 

the Act requires that a minimum of 250 

million gallons of cellulosic biomass 

ethanol be consumed starting in 2013, 

obligated parties will need to be able to 

distinguish RINs representing cellulosic 

biomass ethanol from RINs representing 

other types of renewable fuel. This 

requirement is discussed in more detail 

in Section III.A. 

In the NPRM, the K code served to 

distinguish between standard-value 

RINs and extra-value RINs, and it was 

placed in the middle of the RIN. As 

described more fully in Section III.E.1.a, 

our final rule eliminates the need for a 

distinction between standard-value 

RINs and extra-value RINs, but requires 

a distinction between RINs that must be 

transferred with a volume of renewable 

fuel (assigned RINs) and RINs that can 

be transferred without renewable fuel 

(separated RINs). Thus for the final rule 

we have changed the purpose of the K 

code. As described in Section III.E.2, we 

are requiring that RINs separated from 

volumes of renewable fuel be identified 

as such, by changing the K code from a 

value of 1 to a value of 2. Placing the 

K code at the beginning of the RIN 


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35RIN codes have been separated by hyphens in 

this table for demonstrative purposes only. In actual 

use, no hyphens would be present in the RIN. 

makes this process more straightforward 

for obligated parties and oxygenate 

blenders who will be responsible for 

changing the K code after separating a 

RIN from renewable fuel. 

The RIN also contains two codes 

SSSSSSSS and EEEEEEEE that together 

identify the ‘‘RIN block’’ which 

demarcates the number of gallons of 

renewable fuel that the batch represents 

in the context of compliance. Depending 

on the Equivalence Value, this may not 

necessarily be the same as the actual 

number of gallons in the batch. The 

methodology for designating the 

SSSSSSSS and EEEEEEEE values is 

described in Section III.D.2.b below. 

In the NPRM we assigned six digits to 

the RIN block codes to allow batches up 

to a million gallons in size. Based on 

comments received, we have decided to 

expand the number of digits to eight to 

accommodate batches up to 100 million 

gallons in size. Although it is highly 

unlikely that a single tank would hold 

this volume, we are adding a definition 

of ‘‘batch’’ to our final regulations that 

would allow this high volume to be 

counted as a single batch for the 

purposes of generating RINs. 

In the NPRM we pointed out that 

‘‘RIN’’ can refer to either the number 

representing an entire batch or the 

number representing one gallon of 

renewable fuel in the context of 

compliance. In order to make the 

distinction clear, we are defining the 

latter as a gallon-RIN, and a batch-RIN 

will represent multiple gallon-RINs. In 

the case of a gallon-RIN, the values of 

SSSSSSSS and EEEEEEEE will be 

identical. A batch-RIN, on the other 

hand, will generally have different 

values for SSSSSSSS and EEEEEEEE, 

representing the starting and ending 

values of a batch of renewable fuel. 

Examples of RINs are presented in the 

next section. 

b. Generating RINs 

As described in Section III.E.1.a, we 

have eliminated the distinction between 

standard-value RINs and extra-value 

RINs for this final rule. Instead, all 

gallon-RINs must be assigned to batches 

of renewable fuel by the producer or 

importer. Consistent with the NPRM, 

each gallon-RIN will continue to 

represent one gallon of renewable fuel 

in the context of compliance. 

Also consistent with the NPRM, we 

are requiring that RIN generation begin 

at the same time that the renewable fuel 

standard becomes applicable to 

obligated parties. Thus RINs must be 

generated for all renewable fuel 

produced or imported on or after 

September 1, 2007. Since many 

producers and importers will have 

renewable fuel in inventory at the start 

of the program that was produced prior 

to September 1, 2007, we are also 

allowing them to generate RINs for such 

renewable fuel. This provision ensures 

that every gallon that a producer or 

importer sells starting on September 1, 

2007 can have an assigned RIN, and 

obligated parties that take ownership of 

renewable fuel directly from a producer 

or importer will have greater assurance 

of having access to RINs at the start of 

the program. Other volumes of ethanol 

in inventory in the distribution system 

on September 1, 2007 will continue to 

be sold and distributed without RINs. 

In order to determine the number of 

gallon-RINs that must be generated and 

assigned to a batch by a producer or 

importer, the actual volume of the batch 

must be multiplied by the Equivalence 

Value to determine an applicable ‘‘RIN 

volume’’: 

VRIN = EV × Vs

Where: 

VRIN = RIN volume, in gallons, representing 

the number of gallon-RINs that must be 

generated (rounded to the nearest whole 

gallon). 

EV = Equivalence value for the renewable 

fuel. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons. 

When RINs are first assigned to a 

batch of renewable fuel by its producer 

or importer, the RIN block start for that 

batch will in general be 1 (i.e., 

SSSSSSSS will have a value of 

00000001). The RIN block end value 

EEEEEEEE will be equal to the RIN 

volume calculated above. The batch-RIN 

then represents all the gallon-RINs 

assigned to the batch. Table III.D.2.b–1 

provides some examples of the number 

of gallon-RINs that would be assigned to 

a batch under different circumstances. 

TABLE III.D.2.B–1.—EXAMPLES OF

BATCH-RINS 35

Batch volume: 2000 gallons corn ethanol. 

Equivalence value: 1.0. 

Gallon-RINs: 2000. 

Batch-RIN: 1–2007–1234–12345–00001–10– 

2–00000001–00002000. 

Batch volume: 2000 gallons biodiesel. 

Equivalence value: 1.5. 

Gallon-RINs: 3000. 

Batch-RIN: 1–2007–1234–12345–00002–15– 

2–00000001–00003000. 

Batch volume: 2000 gallons cellulosic ethanol. 

Equivalence value: 2.5. 

Gallon-RINs: 5000. 

Batch-RIN: 1–2007–1234–12345–00003–25– 

1–00000001–00005000. 

The RIN block will often represent the 

actual number of gallons in the batch, 

for cases where the Equivalence Value 

is 1.0. In other cases, the RIN block start 

and RIN block end values in the batchRIN will not exactly correspond to the 

volume of the batch. For instance, in 

cases where the Equivalence Value is 

larger than 1.0, the number of gallonRINs generated will be larger than the 

number of gallons in the batch. In such 

cases the batch will have a greater value 

in terms of compliance than a batch 

with the same volume but an 

Equivalence Value equal to 1.0. 

Likewise, a batch with an Equivalence 

Value less than 1.0 will have a smaller 

value in terms of compliance than a 

batch with the same volume but an 

Equivalence Value equal to 1.0. In the 

context of our modified approach to RIN 

distribution as described in Section 

III.E.1, however, the transfer of RINs 

with batches will be straightforward 

regardless of the number of gallon-RINs 

assigned to a particular volume of 

renewable fuel, as every gallon-RIN will 

always have the capability of covering 

one gallon of an obligated party’s RVO. 

In response to the NPRM, some 

obligated parties requested that 

fractional RINs be used for cases in 

which the Equivalence Value is less 

than 1.0. Under this approach, every 

gallon in a batch would still have an 

assigned gallon-RIN, but those gallonRINs would represent only a fraction of 

a gallon for compliance purposes. The 

commenters also argued that our 

proposed system in which RINs are 

assigned to only a portion of a batch 

would be unworkable given the need to 

ensure that RINs remain assigned to 

batches as they travel through the 

distribution system. 

We continue to believe that the most 

straightforward system calculates the 

number of gallon-RINs representing a 

batch as the product of the Equivalence 

Value and the actual volume of the 

batch. Then every gallon-RIN will have 

the capability of covering one gallon of 

an obligated party’s RVO, and thus 

every gallon-RIN has the same value. 

This is true both for renewable fuels 

with Equivalence Values less than 1.0, 

and renewable fuels with Equivalence 

Values greater than 1.0. Also, as 

described in Section III.E.1, we have 

modified our approach to the 

distribution of RINs assigned to volumes 

of renewable fuel. As a result, the batchsplitting and batch-merging protocols 

have become largely irrelevant, and thus 

the transfer of renewable fuels having an 


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Equivalence Value less than 1.0 has 

become greatly simplified. We are 

therefore finalizing our proposed 

approach in which renewable fuels 

having an Equivalence Value less than 

1.0 result in fewer assigned gallon-RINs 

than gallons in a batch. 

Following release of the NPRM, we 

also identified some cases in which the 

generation of RINs for a partially 

renewable fuel or blending component 

would result in double-counting of RINs 

generated. For instance, ethyl tertiary 

butyl ether (ETBE) is made from 

combining ethanol with isobutylene. 

The ethanol is generally from corn, and 

the isobutylene is generally from 

petroleum. The ETBE producer may 

purchase ethanol from another source, 

and that ethanol may already have RINs 

assigned to it. In such cases it would not 

be appropriate for the ETBE producer to 

generate additional RINs for the ETBE 

made from that ethanol. Even if the 

ETBE producer purchased ethanol 

without assigned RINs, our program 

design ensures that either RINs were 

generated for the ethanol and separated 

prior to purchase by the ETBE producer, 

or RINs were legitimately not assigned 

to the ethanol. The NPRM did not 

address the potential for generating 

RINs twice for the same renewable fuel 

in these cases. Therefore, we are 

finalizing a provision prohibiting a 

party from generating RINs for a 

partially renewable fuel or blending 

component that it produces if the 

renewable feedstock used to make the 

renewable fuel or blending component 

was acquired from another party. Any 

RINs acquired with the renewable 

feedstock (e.g. ethanol) must be assigned 

to the product made from that feedstock 

(e.g. ETBE). This approach is consistent 

with comments submitted by Lyondell 

Chemical Company. 

c. Cases in Which RINS Are Not 

Generated 

Although in general every batch of 

renewable fuel produced or imported 

must have an assigned batch-RIN, there 

are several cases in which a RIN may 

not be assigned to a batch by a producer 

or importer. For instance, if the 

renewable fuel was consumed within 

the confines of the production facility 

where it was made, it would not be 

acquired by either an obligated party or 

a gasoline blender. In such cases, the 

RIN could not be separated from the 

batch and transferred separately since 

producers do not have this right. A RIN 

is assigned to renewable fuel when 

ownership of the renewable fuel is 

transferred to another party. Since no 

such transfer would occur in this case, 

no RIN should be generated. 

A second case in which some 

renewable fuel would not have an 

assigned RIN would occur for small 

volume producers. We are allowing 

renewable fuel producers who produce 

less than 10,000 gallons in a year to 

avoid the requirement to generate RINs 

and assign them to batches. Such 

producers would not contribute 

meaningfully to the nationwide pool of 

renewable fuel, and we do not believe 

that the very small business operations 

involved should be subject to the 

burden of recordkeeping and reporting. 

Although two commenters disagreed 

that these small volume producers 

should be exempt from the requirement 

to generate RINs, they did not provide 

compelling evidence that the exemption 

would create a problem in the 

distribution system or provide an unfair 

advantage to small producers. As a 

result we are finalizing this provision as 

proposed. Note that if a small producer 

chooses to register as a renewable fuel 

producer under the RFS program, they 

will be subject to all the regulatory 

provisions that apply to all producers, 

including the requirement to assign 

RINs to batches. 

In the NPRM we proposed that a 

renewable fuel producer which also 

operated as an exporter would not be 

required to generate and assign a RIN to 

any renewable fuel that it produced and 

exported. However, one commenter 

pointed out that this approach could 

lead to confusion regarding which 

gallons should have an assigned RIN 

and which should not, given the 

complex nature of tracking volumes of 

renewable fuel. As a result we have 

determined that this provision should 

be eliminated. Our final regulations 

require that producers assign RINs to all 

renewable fuel, regardless of whether it 

is exported. Exports of renewable fuel 

are discussed further in Section III.D.4. 

3. Calculating and Reporting 

Compliance 

Under our program, RINs form the 

basis of the volume accounting and 

tracking system that allows each 

obligated party to demonstrate that they 

have met their renewable fuel obligation 

each year. This section describes how 

the compliance process using RINs 

works. Our approach to the distribution 

and trading of RINs is covered 

separately in Section III.E below. 

a. Using RINs To Meet the Standard 

Under our program, each obligated 

party must determine its Renewable 

Volume Obligation (RVO) based on the 

applicable percentage standard and its 

annual gasoline volume as described in 

Section III.A.4. The RVO represents the 

volume of renewable fuel that the 

obligated party must ensure is used in 

the U.S. in a given calendar year. Since 

the nationwide renewable fuel volumes 

shown in Table I.B–1 are required by 

the Act to be consumed in whole 

calendar years, each obligated party 

must likewise calculate its RVO on an 

annual basis. 

Since our program uses RINs as a 

measure of the amount of renewable 

fuel used as motor vehicle fuel that is 

sold or introduced into commerce 

within the U.S., obligated parties must 

meet their RVO through the 

accumulation of RINs. In so doing, they 

will effectively be causing the 

renewable fuel represented by the RINs 

to be consumed as motor vehicle fuel. 

Obligated parties are not required to 

physically blend the renewable fuel into 

gasoline or diesel fuel themselves. The 

accumulation of RINs is the means 

through which each obligated party 

shows compliance with its RVO and 

thus with the renewable fuel standard. 

For each calendar year, each obligated 

party is required to submit a report to 

the Agency documenting the RINs it 

acquired and showing that the sum of 

all gallon-RINs acquired is equal to or 

greater than its RVO. This reporting is 

discussed in more detail in Section IV. 

In the context of demonstrating 

compliance, all gallon-RINs have the 

same compliance value. The Agency can 

then verify that the RINs used for 

compliance purposes are valid by 

simply comparing RINs reported by 

producers to RINs claimed by obligated 

parties. We can also verify simply that 

any given gallon-RIN was not doublecounted, i.e., used by more than one 

obligated party for compliance 

purposes. In order to be able to identify 

the cause of any double-counting, 

however, additional information is 

needed on RIN transactions as discussed 

in Section IV. 

If an obligated party has acquired 

more RINs than it needs to meet its 

RVO, then in general it can retain the 

excess RINs for use in complying with 

its RVO in the following year or transfer 

the excess RINs to another party. The 

conditions under which this is allowed 

are determined by the valid life of a 

RIN, described in more detail in Section 

III.D.3.b below. If, alternatively, an 

obligated party has not acquired 

sufficient RINs to meet its RVO, then 

under certain conditions it can carry a 

deficit into the next year. Deficit 

carryovers are discussed in more detail 

in Section III.D.3.d. 

The regulations prohibit any party 

from creating or transferring invalid 

RINs. Invalid RINs cannot be used in 

demonstrating compliance regardless of 


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36The use of previous-year RINs for current year 

compliance purposes will also be limited by the 20 

percent RIN rollover cap under today’s final rule. 

However, as discussed in the next section, we 

believe that this cap will still provide a significant 

amount of flexibility to obligated parties. 

the good faith belief of a party that the 

RINs are valid. These enforcement 

provisions are necessary to ensure the 

RFS program goals are not compromised 

by illegal conduct in the creation and 

transfer of RINs. 

As in other motor vehicle fuel credit 

programs, the regulations address the 

consequences if an obligated party is 

found to have used invalid RINs to 

demonstrate compliance with its RVO. 

In this situation, the refiner or importer 

that used the invalid RINs will be 

required to deduct any invalid RINs 

from its compliance calculations. The 

refiner or importer will be liable for 

violating the standard if the remaining 

number of valid RINs is insufficient to 

meet its RVO, and the obligated party 

may be subject to additional monetary 

penalties if it used invalid RINs in its 

compliance demonstration. See Section 

V of this preamble for further discussion 

regarding liability for use of invalid 

RINs. 

Just as for RIN generators, we are also 

requiring that obligated parties conduct 

attest engagements for the volume of 

gasoline they produce and the number 

of RINs procured to ensure compliance 

with their RVO. In most cases, this 

should amount to little more than is 

already required under existing EPA 

gasoline regulations. In the case of 

renewable fuel exporters, the attest 

engagement will verify the volume of 

renewable fuel exported and therefore 

the magnitude of their RVO. Attest 

engagement reports must be submitted 

to the party that commissioned the 

engagement and to EPA. See Section IV 

of this preamble for further discussion 

of the attest engagement requirements. 

b. Valid Life of RINs 

The Act requires that renewable fuel 

credits be valid for showing compliance 

for 12 months as of the date of 

generation. This section describes our 

interpretation of this provision in the 

context of our program wherein excess 

RINs fulfill the Act’s requirements 

regarding credits. 

As discussed in Section III.D.1.a, we 

interpret the Act such that credits 

would represent renewable fuel 

volumes in excess of what an obligated 

party needs to meet their annual 

compliance obligation. Given that the 

renewable fuel standard is an annual 

standard, obligated parties will 

determine compliance shortly after the 

end of the year, and credits would be 

identified at that time. Obligated parties 

will typically demonstrate compliance 

by submitting a compliance 

demonstration to EPA. Given the 12- 

month life of a credit as stated in the 

Act, we interpret this provision as 

meaning that credits would only be 

valid for compliance purposes for the 

following compliance year. Hence if a 

refiner or importer overcomplied with 

their 2007 obligation they would 

generate credits that could be used to 

show compliance with the 2008 

compliance obligation, but the credits 

could not be used to show compliance 

for later years. Since RINs fulfill the role 

of credits, the statutory provisions 

regarding credits apply to RINs 

The Act’s limit on credit life helps 

balance the risks between the needs of 

renewable fuel producers and obligated 

parties. Producers are currently making 

investments in expanded production 

capacity on the expectation of a 

statutorily guaranteed minimum 

quantity demanded. Under the market 

conditions we are experiencing today 

that make ethanol use more 

economically attractive, the annual 

volume requirements in the RFS 

program will not drive consumption of 

renewable fuels. However, if the price of 

crude oil dropped significantly or the 

use of ethanol in gasoline became 

otherwise less economically attractive, 

obligated parties could use stockpiled 

credits to comply with the program 

requirements. As a result, demand for 

renewable fuel could fall well below the 

RFS program requirements, and many 

producers could end up with a stranded 

investment. The 12 month valid life 

limit for credits minimizes the potential 

for this type of result. 

For obligated parties, the Act’s 12 

month valid life for credits provides a 

window within which parties who do 

not meet their renewable fuel obligation 

through their own physical use of 

renewable fuel can obtain credits from 

other parties who have excess. This 

critical aspect of the trading system 

allows the renewable fuels market to 

continue operating according to natural 

market forces, avoiding the possibility 

that every single refiner would need to 

purchase renewable fuel for blending 

into its own gasoline. But the 12 month 

life also provides a window within 

which banking and trading can be used 

to offset the negative effects of 

fluctuations in either supply of or 

demand for renewable fuels. For 

instance, if crude oil prices were to drop 

significantly and natural market 

demand for ethanol likewise fell, the 

RFS program would normally bring 

demand back up to the minimum 

required volumes shown in Table I.B–1. 

But in this circumstance, the use of 

ethanol in gasoline would be less 

economically attractive, since demand 

for ethanol would not be following price 

but rather the statutorily required 

minimum volumes. As a result, the 

price of credits as represented by RINs, 

and thus ethanol blends, could rise 

above the levels that would exist if no 

minimum required volumes existed. 

The 12 month valid life creates some 

flexibility in the market to help mitigate 

price fluctuations. The renewable fuels 

market could also experience a 

significant drop in supply if, for 

instance, a drought were to limit the 

production of the feedstocks needed to 

produce renewable fuel. Obligated 

parties could use banked credits to 

comply rather than carry a deficit into 

the next year. 

In the context of our RIN-based 

program, we have been able to 

accomplish the same objective as the 

Act’s 12 month life of credits by 

allowing RINs to be used to show 

compliance for the year in which the 

renewable fuel was produced and its 

associated RIN first generated or for the 

following year. RINs not used for 

compliance purposes in the year in 

which they were generated will by 

definition be in excess of the RINs an 

obligated party needed in that year, 

making excess RINs equivalent to the 

credits referred to in the Energy Act. 

Excess RINs are valid for compliance 

purposes in the year following the one 

in which they initially came into 

existence.36 RINs not used within their 

valid life will expire. This approach 

satisfies the Act’s 12 month duration for 

credits. 

Thus we are requiring that every RIN 

be valid for the calendar-year 

compliance period in which it was 

generated or the following year. If a RIN 

was created in one year but was not 

used by an obligated party to meet its 

RVO for that year, the RIN can be used 

for compliance purposes in the next 

year (subject to certain provisions to 

address RIN rollover as discussed 

below). If, however, a RIN was created 

in one year and was not used for 

compliance purposes in that year or in 

the next year, it will expire. In response 

to the NPRM, this approach was 

supported by a number of obligated 

parties and their representative 

associations. These commenters agreed 

that allowing RINs to be used for the 

year generated or the following year was 

not only supported by the statutory 

language, but was also an element of 

program flexibility that would be 

critical for offsetting the negative effects 

of potential fluctuations in either supply 

of or demand for renewable fuels. 


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However, in response to our NPRM, 

other commenters said that the Energy 

Act’s 12-month credit life provision 

should be interpreted as applying 

retrospectively, not prospectively. 

Under this approach, the 12-month 

timeframe in the Act would be 

interpreted to refer to the full calendar 

year within which a credit was 

generated. Under this alternative 

approach no RINs could be used for 

compliance purposes beyond the 

calendar year in which they originally 

came into existence. As discussed 

below, we do not believe that this 

approach is appropriate. 

Commenters who supported the 

retrospective approach to the Act’s 12- 

month credit life provision argued that 

the Energy Act could have been written 

to explicitly allow a valid life of 

multiple years if that had been 

Congress’ intent. In response, the Act 

explicitly indicates that obligated 

parties may either use the credits they 

have generated or transfer them. For a 

party to be able to use credits generated, 

such credit use must necessarily occur 

in a compliance year other than the one 

in which the credit was generated. Thus 

we do not believe that a retrospective 

approach to the Act’s 12-month credit 

life provision is consistent with the 

explicit credit provisions of the Act. In 

addition, we believe that an 

interpretation leading to a valid life of 

one year after the year in which the RIN 

was generated is most consistent with 

the program as a whole. In comparison 

to a single-year valid life for RINs, our 

approach provides some additional 

compliance flexibility to obligated 

parties as they make efforts to acquire 

sufficient RINs to meet their RVOs each 

year. This flexibility will have the effect 

of keeping fuel costs lower than they 

would otherwise be. 

In the comments we received on the 

NPRM, one objection to our proposed 

approach was that the use of RINs 

generated in one compliance period to 

satisfy obligations in a subsequent 

compliance period could result in less 

renewable fuel used in a given year than 

is set forth in the statute. While this is 

true, we believe this approach is most 

consistent with the Act, as described 

above. The Act clearly set up a credit 

program with a credit life, meaning 

Congress intended parties to use credits 

in some cases instead of blending 

renewable fuel. The Act is best read to 

harmonize all of its provisions. In 

addition, we note that other provisions 

of the Act may lead to less renewable 

fuel use in a given year than the 

statutorily-prescribed volumes, but 

Congress adopted them and intended 

that they could be used. For instance, 

the deficit carryover provision allows 

any obligated party to fail to meet its 

RVO in one year if it meets the deficit 

and its RVO in the next year. If several 

obligated parties took advantage of this 

provision, it could result in the 

nationwide total volume obligation for a 

particular calendar year not being met. 

In a similar fashion, the statutory 

requirement that every gallon of 

cellulosic biomass ethanol be treated as 

2.5 gallons for the purposes of 

compliance means that the annually 

required volumes of renewable fuel 

could be met in part by virtual, rather 

than actual, volumes. Finally, the 

calculation of the renewable fuel 

standard is based on projected 

nationwide gasoline volumes provided 

by EIA (see Section III.A). If the 

projected gasoline volume falls short of 

the actual gasoline volume in a given 

year, the standard will fail to create the 

demand for the full renewable fuel 

volume required by the Act for that 

year. The Act contains no provision for 

correcting for underestimated gasoline 

volumes. Additional responses to the 

issues raised by commenters on RIN life 

can be found in the S&A document. 

c. Cap on RIN Use To Address Rollover 

As described in Section III.D.3.b 

above, RINs are valid for compliance 

purposes for the calendar year in which 

they are generated or the following year. 

We believe that this approach is most 

consistent with the Act’s prescription 

that credits be valid for compliance 

purposes for 12 months as of the date of 

generation. Our approach is intended to 

address both the risk taken by producers 

expecting a guaranteed demand to cover 

their expanded production capacity 

investments and the risk taken by 

obligated parties who need a guaranteed 

supply in order to meet their regulatory 

obligations under this program. 

However, the use of previous year 

RINs to meet current year compliance 

obligations does create an opportunity 

for effectively circumventing the valid 

life limit for RINs. This can occur in 

situations wherein the total number of 

RINs generated each year for a number 

of years in a row exceeds the number of 

RINs required under the RFS program 

for those years. The excess RINs 

generated in one year could be used to 

show compliance in the next year, 

leading to the generation of new excess 

RINs in the next year, causing the total 

number of excess RINs in the market to 

accumulate over multiple years despite 

the limit on RIN life. The NPRM 

included examples of how this 

‘‘rollover’’ might occur. The rollover 

issue would in some circumstances 

essentially make the applicable valid 

life for RINs virtually meaningless in 

practice. 

RIN rollover also undermines the 

ability of a limit on credit life to 

guarantee a market for renewable fuels. 

As described in Section III.D.3.b, if the 

natural market demand for ethanol was 

higher than the volumes required under 

the RFS program for several years in a 

row, as may occur in practice, obligated 

parties could amass RINs that, in the 

extreme, could be used entirely in lieu 

of actually demanding ethanol in some 

subsequent year. 

As described in the NPRM, we believe 

that the rollover issue must be 

addressed. The Act’s provision 

regarding the valid life of credits is 

clearly intended to obtain the benefits 

associated with a limited credit life. 

Any program structure in which some 

RINs effectively have an infinite life, 

regardless of the technical life of 

individual RINs, does not appropriately 

achieve the benefits expected from the 

Act’s provision regarding the 12-month 

life of credits. The authority to establish 

a credit program and to implement a 

limited life for credits includes the 

authority to limit actions that have the 

practical effect of circumventing this 

limited credit life. 

To be consistent with the Act, we 

believe that the rollover issue should be 

addressed in our regulations. However, 

we also believe that the limits to 

preclude such unhindered rollovers 

should not preclude all previous-year 

RINs from being used for current-year 

compliance. To accomplish this, we 

must restrict the number of previousyear RINs that can be used for current 

year compliance. To this end, we 

proposed a 20 percent cap on the 

amount of an obligated party’s 

Renewable Volume Obligation (RVO) 

that can be met using previous-year 

RINs. After review of the comments we 

received on the NPRM, we have decided 

to finalize this provision. Thus each 

obligated party will be required to use 

current-year RINs to meet at least 80 

percent of its RVO, with a maximum of 

20 percent being derived from previousyear RINs. Any previous-year RINs that 

an obligated party may have that are in 

excess of the 20 percent cap can be 

traded to other obligated parties that 

need them. If the previous-year RINs in 

excess of the 20 percent cap are not 

used by any obligated party for 

compliance, they will expire. The net 

result will be that, for the market as a 

whole, no more than 20 percent of a 

given year’s renewable fuel standard can 

be met with RINs from the previous 

year. 

As described in the NPRM, we believe 

that the 20 percent cap provides the 


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appropriate balance between, on the one 

hand, allowing legitimate RIN 

carryovers and protecting against 

potential supply shortfalls that could 

limit the availability of RINs, and on the 

other hand ensuring an annual demand 

for renewable fuels as envisioned by the 

Act. We believe this approach also 

provides the certainty all parties desire 

in implementing the program. The same 

cap will apply equally to all obligated 

parties, and the cap will be the same for 

all years, providing certainty on exactly 

how obligated parties must comply with 

their RVO going out into the future. A 

20 percent cap will be readily 

enforceable with minimal additional 

program complexity, as each obligated 

party’s annual report will simply 

provide separate listings of previousyear and current-year RINs to establish 

that the cap has not been exceeded. A 

20 percent cap will have no impact on 

who could own RINs, their valid life, or 

any other regulatory provision regarding 

compliance. 

Some NPRM commenters did not 

perceive a problem with the RIN 

rollover issue and argued for no rollover 

cap or at least for a more flexible one. 

They pointed to the need for maximum 

flexibility in responding to fluctuations 

in the market, and they were primarily 

concerned about potential supply 

problems. For instance, if a drought 

were to reduce the availability of corn 

for ethanol production, there may 

simply not be sufficient RINs available 

for compliance purposes. A drought 

situation actually occurred in 1996, and 

as a result 1996 ethanol production was 

21% less than it had been in 1995. In 

1997, production had not yet returned 

to the 1995 levels. Moreover, there is no 

guarantee that future droughts, should 

they occur, would result in a reduction 

in ethanol production of only 21 

percent. As a result, in the NPRM we 

requested comment on whether a higher 

cap, such as 30 percent, would be more 

appropriate. A number of refiners and 

refinery associations commented that 30 

percent would indeed provide them 

with the additional flexibility they 

would need in the case of a significant 

market disruption. Some requested a 

cap of 40 percent or even no cap at all. 

These parties also expressed concern 

that, although the Agency has the 

authority to waive the required 

renewable fuel volumes in whole or in 

part in the event of inadequate domestic 

supply, this can occur only on petition 

by one or more states and then only 

after consultation with both the 

Department of Agriculture and the 

Department of Energy. Some obligated 

parties expressed concern that such a 

waiver would not occur in a timely 

fashion. The availability of excess 

previous-year RINs would thus provide 

compliance certainty in the event that 

the supply of current-year RINs falls 

below the RFS program requirements 

and the Agency does not waive any 

portion of the program requirements. 

In contrast to obligated parties, 

renewable fuel producers provided 

comments on the NPRM indicating that 

10 percent would be more appropriate. 

They argued that a 10 percent cap was 

closer to their preferred approach to RIN 

life in which the Act’s 12-month life of 

a credit is interpreted as allowing RINs 

to be used for compliance purposes only 

in the year in which they are generated. 

We continue to believe that a cap set 

at 20 percent is appropriate, and the 

comments submitted in response to the 

NPRM did not provide compelling 

evidence to the contrary. The level of 20 

percent is consistent with past ethanol 

market fluctuations. As described above, 

the largest single-year drop in ethanol 

supply occurred in 1996 and resulted in 

21% less ethanol being produced than 

in 1995. While future supply shortfalls 

may be larger or smaller, the 

circumstances of 1996 provide one 

example of their potential magnitude. 

We believe that a cap of 20 percent is 

a reasonable way to limit RIN rollover 

and provide some assurances to 

renewable fuel producers regarding 

demand for renewable fuel. A cap of 20 

percent also ensures that many 

previous-year RINs can still be used for 

current year compliance, providing 

some flexibility in the event of market 

disruptions. 

Given the competing needs expressed 

by renewable fuel producers and 

refiners, a rollover cap of 20 percent 

also balances the risk taken by 

producers of renewable fuels expecting 

a guaranteed quantity demanded to 

cover their production capacity 

investments and the risk taken by 

obligated parties who need a guaranteed 

supply in order to meet their regulatory 

obligations under this program. We are 

therefore finalizing a rollover cap of 20 

percent. 

In the NPRM we also considered an 

alternative approach whereby we would 

set the cap annually based on the actual 

excess renewable fuel production. We 

did not propose this approach, and 

commenters did not support it. We have 

determined that fixing the cap at 20 

percent both provides certainty to the 

RIN market and ensures that some 

minimum level of flexibility exists for 

individual obligated parties even in a 

market without excess RINs. 

We also requested comment on 

whether the Agency should adopt a 

provision allowing the cap to be raised 

in the event that supply shortfalls 

overwhelmed the 20 percent cap. Under 

this conditional provision, the Agency 

would monitor standard indicators of 

agricultural production and renewable 

fuel supply to determine if sufficient 

volumes of renewable can be produced 

to meet the RFS program requirements 

in a given year. Prior to the end of a 

compliance period, if the Agency 

determined that a supply shortfall was 

imminent, it could raise the cap to 

permit a greater number of previousyear RINs to be used for current-year 

compliance. Although this approach 

would not change the required volumes, 

it could create some additional 

temporary flexibility. However, we did 

not propose this provision, and 

commenters did not address it. We do 

not believe it is necessary, and thus we 

have not finalized it. 

Finally, the cap is designed to prevent 

the rollover of RINs generated two years 

ago from being used for compliance 

purposes in the current year. No RINs 

were generated in 2006 when the 

default standard of 2.78 percent was in 

effect on a collective basis, so the first 

year in which RINs will be generated is 

2007. Consequently, the first year in 

which there could be rollover would be 

2009. Therefore, we proposed that the 

cap would not be effective until 

compliance year 2009. Two commenters 

pointed out that this approach could 

under some scenarios lead to a situation 

in which more than 20 percent of the 

RINs used for compliance purposes in 

2008 were actually generated in the 

previous year, 2007. EPA believes that 

implementing the rollover cap in 2008 

would, indeed, prevent the initiation of 

an excess buildup of past RINs. In 

addition, it would simplify the 

regulations, since there would be no 

need for an exception from the RIN cap 

for 2008. Consequently we are finalizing 

the 20 percent cap to apply to all years, 

including 2008. 

d. Deficit Carryovers 

The Energy Act also contains a 

provision allowing an obligated party to 

carry a deficit forward from one year 

into the next if it cannot comply with 

its RVO. However, deficits cannot be 

carried over two years in a row. 

Deficit carryovers are measured in 

gallons of renewable fuel, just as for 

RINs and RVOs. If an obligated party 

does not acquire sufficient RINs to meet 

its RVO in a given year, the deficit is 

calculated by subtracting the total 

number of RINs an obligated party has 

acquired from its RVO. There are no 

volume penalties, discounts, or other 

factors included when calculating a 


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deficit carryover. As described in 

Section III.D.1, the deficit is then added 

to the RVO for the next year. The 

calculation of the RVO as described in 

Section III.A.4 shows how a deficit 

would be carried over into the next year: 

RVOi = (Stdi × GVi) + Di-1

Where: 

RVOi = The Renewable Volume Obligation 

for the obligated party for year i, in 

gallons. 

Stdi = The RFS program standard for year i, 

in percent. 

GVi = The non-renewable gasoline volume 

produced by an obligated party in year 

i, in gallons. 

Di-1 = Renewable fuel deficit carryover from 

the previous year, in gallons. 

If an obligated party does not acquire 

sufficient RINs to meet its RVO in year 

i-1, the obligated party must procure 

sufficient RINs to cover the full RVO for 

year i including the deficit. There are no 

provisions allowing for another year of 

carryover. If the obligated party does not 

acquire sufficient RINs to meet its RVO 

for that year plus the deficit carryover 

from the previous year, it will be in 

noncompliance. 

The Act indicates that deficit 

carryovers are to occur due to 

‘‘inability’’ to generate or purchase 

sufficient credits. We believe that 

obligated parties will make a 

determined effort to satisfy their RVO 

on an annual basis and that a deficit 

will demonstrate that they were unable 

to do so. Thus, we did not propose that 

any particular demonstration of 

‘‘inability’’ be a prerequisite to the 

ability of obligated parties to carry 

deficits forward. However, one 

commenter requested that we should 

establish some sort of standard or 

threshold that obligated parties must 

meet before they would be allowed to 

use the deficit carryover provision. 

Although the commenter provided no 

suggestions regarding how such a 

threshold could be established, he 

indicated that in the absence of such a 

threshold obligated parties could 

potentially use the deficit carryover 

provision to undermine the amount of 

actual renewable fuel used in a given 

year. 

We agree that the deficit carryover 

provision could result in less renewable 

fuel being consumed in a given year 

than is required by the Act, especially 

if several obligated parties took 

advantage of it at the same time. 

However, in any given year some parties 

may be making up deficits from a prior 

year, while other parties might be 

generating deficits. This fact will tend to 

reduce the net effect in any given year, 

and regardless, the deficit in demand in 

one year will by regulatory requirement 

be made up in the following year. 

Finally, any threshold we could set to 

demonstrate an obligated party’s 

inability to generate or purchase 

sufficient credits would likely require a 

comprehensive investigation of their 

opportunities to acquire RINs. Such 

investigations would consume Agency 

resources that would be better spent, in 

terms of ensuring that the goals of the 

Act are met, on other compliance 

enforcement matters. Therefore, we 

have not set any thresholds in the final 

rule. 

4. Provisions for Exporters of Renewable 

Fuel 

As described in Section III.D.2.a, we 

believe that U.S. consumption of 

renewable fuel as motor vehicle fuel can 

be measured with considerable accuracy 

through the tracking of renewable fuel 

production and importing records. This 

is the basis for our RIN-based system of 

compliance. However, exports of 

renewable fuel must be accounted for 

under this approach. For instance, if a 

gallon of ethanol is produced in the U.S. 

but consumed outside of the U.S., the 

RIN associated with that gallon is not 

valid for RFS compliance purposes 

since the RFS program is intended to 

require a specific volume of renewable 

fuel to be consumed in the U.S. Exports 

of renewable fuel currently represent 

about 5 percent of U.S. production, 

though the exact value varies each year. 

To ensure that renewable fuels 

exported from the U.S. cannot be used 

by an obligated party for RFS 

compliance purposes, the RINs 

associated with that exported renewable 

fuel must be removed from circulation. 

For this final rule we have concluded 

that it should be the exporter’s 

responsibility to account for exported 

renewable fuel in our RIN-based 

program. We are therefore requiring that 

an RVO be assigned to each exporter 

that is equal to the annual volume of 

renewable fuel it exported. Just as for 

obligated parties, then, the exporter is 

required to acquire sufficient gallonRINs to meet its RVO. If the exporter 

purchases renewable fuel directly from 

a producer, that renewable fuel will 

come with associated gallon-RINs which 

can then be applied to its RVO under 

our program. In this circumstance, the 

exporter will not need to acquire RINs 

from any other source. If, however, the 

exporter receives renewable fuel 

without the associated RINs, it will need 

to acquire RINs from some other source 

in order to meet its RVO. 

In the NPRM we presented an 

alternative approach which would have 

increased the obligation placed on 

refiners and importers of gasoline based 

on the volume of renewable fuel 

exported. One commenter supported 

this alternative approach, explaining 

that the proposed approach of requiring 

the exporter to acquire sufficient RINs to 

offset an RVO equal to the exported 

volume would place a significant 

recordkeeping burden on exporters. 

This commenter also expressed concern 

that exporters would receive no value in 

return for compliance with an RVO. We 

do not believe that these are compelling 

reasons to place the burden for exported 

renewable fuel on obligated parties. Not 

only would this alternative approach 

have required an estimate of the volume 

of renewable fuel exported in the next 

year, but would also mean that every 

obligated party would share in 

accumulating RINs to cover the 

activities of other parties not under their 

control. 

In the NPRM we pointed out that in 

specific circumstances involving 

exports of renewable fuels, the need for 

RINs might not be necessary. For 

instance, if the exporter was wholly 

owned by a renewable fuel producer, 

there would be no need to generate RINs 

for the exported product. We therefore 

proposed to allow exported product to 

be excluded from the exporter’s RVO if 

the exporter was also the producer and 

no RINs were generated for that product. 

However, one commenter pointed out 

that this approach could lead to 

confusion regarding which gallons 

should have an assigned RIN and which 

should not, given the complex nature of 

tracking volumes of renewable fuel. As 

a result we have determined that this 

provision should be eliminated. Our 

final regulations require producers to 

assign RINs to all renewable fuel, 

regardless of whether it is exported. In 

this case the renewable producer would 

merely use these RINs to cover its 

obligation as an exporter. 

As described in Section III.D.2, there 

are cases in which there is not a one-toone correspondence between gallons in 

a batch of renewable fuel and the gallonRINs generated for that batch. If the 

RVO assigned to the exporter were 

based strictly on the actual volume of 

the exported product, it would not 

necessarily capture all the gallon-RINs 

which were generated for that exported 

volume. Thus we are requiring that the 

RVO assigned to an exporter be based 

not on the actual volume of renewable 

fuel exported, but rather on a volume 

adjusted by the Equivalence Value 

assigned to each batch. The Equivalence 

Value is represented by the RR code 

within the RIN as described in Section 

III.D.2.a. Thus the exporter must 

multiply the actual volume of a batch by 


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that batch’s Equivalence Value to obtain 

the volume used to calculate the RVO. 

In cases wherein an exporter obtains 

a batch of renewable fuel whose RIN has 

already been separated by an obligated 

party or blender, the exporter may not 

know the Equivalence Value. We are 

requiring that for such cases the 

exporter use the equivalence value 

applicable to that type of renewable fuel 

(e.g., 1.5 for biodiesel). However, in the 

case of ethanol, the same product could 

have been produced as corn ethanol or 

cellulosic ethanol. Thus, in the case of 

ethanol, if the exporter does not know 

the equivalence value we are requiring 

that the exporter use the actual volume 

of the batch to calculate its RVO. This 

will introduce some small error into the 

calculation of the RVO for cases in 

which the ethanol had in fact been 

assigned an Equivalence Value of 2.5. 

However, we believe that the potential 

impact of this on the overall program 

will be exceedingly small. 

5. How Will the Agency Verify 

Compliance? 

The primary means through which 

the Agency will verify an obligated 

party’s compliance with its RVO will be 

the annual compliance demonstration 

reports. These reports will include a 

variety of information required for 

compliance and enforcement, including 

the demonstration of compliance with 

the previous calendar year’s RVO, a list 

of all transactions involving RINs, and 

the tabulation of the total number of 

RINs owned, used for compliance, 

transferred, retired and expired. 

Reporting requirements for obligated 

and non-obligated parties are covered in 

detail in Section IV. 

In its annual reports, an obligated 

party will be required to include a list 

of all RINs held as of the reporting date, 

divided into a number of categories. For 

instance, a distinction must be made 

between current-year RINs and 

previous-year RINs as follows: 

Current-year RINs: RINs that came 

into existence during the calendar year 

for which the report is demonstrating 

compliance. 

Previous-year RINs: RINs that came 

into existence in the calendar year 

preceding the year for which the report 

is demonstrating compliance. 

The report must also indicate which 

RINs have been used for compliance 

with the RVO including any potential 

deficit, which current-year RINs have 

not been used for compliance and are 

therefore valid for compliance the next 

year, and which previous-year RINs 

have not been used for compliance and 

therefore expire. The report must also 

include a demonstration that the 

obligated party had not exceeded the 20 

percent cap to address RIN rollover, as 

described in Section III.D.3.c. 

In order to verify compliance for each 

obligated party, the primary Agency 

activity will involve the validation of 

RINs. The Agency will perform the 

following four basic elements of RIN 

validation: 

(1) RINs used by an obligated party to 

comply with its RVO will be checked to 

ensure that they are within their twoyear valid life. The RIN itself will 

contain the year of generation, so this 

check involves only an examination of 

the listed RINs. 

(2) All RINs owned by an obligated 

party will be cross-checked with reports 

from renewable fuel producers to verify 

that each RIN had in fact been 

generated. 

(3) All RINs used by an obligated 

party for compliance purposes will be 

cross-checked with annual reports from 

other obligated parties to ensure that no 

two parties used the same RIN to 

comply. 

(4) Previous-year RINs used for 

compliance purposes will be checked to 

ensure that they do not exceed 20 

percent of the obligated party’s RVO. 

In cases where a RIN is highlighted 

under suspicion of being invalid, the 

Agency will then need to take 

additional steps to resolve the issue. In 

general this will involve a review of RIN 

transfer records submitted quarterly to 

the Agency by all parties in the 

distribution system that held the RINs. 

RIN transfers will be recorded through 

EPA’s Central Data Exchange as 

described in Section IV. These RIN 

transfer records will permit the Agency 

to identify all transaction(s) involving 

the RINs in question. The Agency can 

then contact liable parties and take 

appropriate steps to formally invalidate 

a RIN improperly claimed by a 

particular party. Additional details of 

the liabilities and prohibitions 

attributed to parties in the distribution 

system are discussed in Section V. 

E. How Are RINs Distributed and 

Traded? 

Under our final program structure, a 

Renewable Identification Number (RIN) 

must (with certain exceptions) be 

generated for all renewable fuel 

produced or imported into the U.S., and 

RINs must be acquired by obligated 

parties for use in demonstrating 

compliance with the RFS requirements. 

However, as described in the NPRM, 

there are a variety of ways in which 

RINs could theoretically be transferred 

from the point of generation by 

renewable fuel producers to the 

obligated parties that need them. 

EPA’s final program was developed in 

light of the somewhat unique aspects of 

the RFS program. As discussed earlier, 

under this program the refiners and 

importers of gasoline are the parties 

obligated to comply with the renewable 

fuel requirements. At the same time, 

refiners and importers do not generally 

produce or blend renewable fuels at 

their facilities and so are dependent on 

the actions of others for the means of 

compliance. Unlike EPA’s other fuel 

programs, the actions needed for 

compliance largely center on the 

production, distribution, and use of a 

product by parties other than refiners 

and importers. In this context, we 

believe that the RIN transfer mechanism 

should focus primarily on facilitating 

compliance by refiners and importers 

and doing so in a way that imposes 

minimum burden on other parties and 

minimum disruption of current 

mechanisms for distribution of 

renewable fuels. 

Our final program does this by relying 

on the current market structure for 

ethanol distribution and use and 

avoiding the need for creation of new 

mechanisms for RIN distribution that 

are separate and apart from this current 

structure. Our program basically 

requires RINs to be transferred with 

renewable fuel until the point at which 

the renewable fuel is purchased by an 

obligated party or is blended into 

gasoline or diesel fuel by a blender. This 

approach allows the RIN to be 

incorporated into the current market 

structure for sale and distribution of 

renewable fuel, and avoids requiring 

refiners to develop and use wholly new 

market mechanisms. While the 

development of new market 

mechanisms to distribute RINs is not 

precluded under our program, it is also 

not required. 

In the NPRM the Agency also 

evaluated several options for 

distributing RINs other than the option 

incorporated into today’s rule. We are 

not finalizing these alternatives because 

they tend to require the development of 

new market mechanisms, as compared 

to relying on the current market 

structure for distribution of ethanol, and 

they are less focused on facilitating 

compliance for the obligated parties. 

1. Distribution of RINs With Volumes of 

Renewable Fuel 

We are requiring that RINs be 

transferred with volumes of renewable 

fuel as they move through the 

distribution system, until ownership of 

those volumes is assumed by an 

obligated party, exporter, or a party that 

converts the renewable fuel into motor 

vehicle fuel. At such time, RINs can be 


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separated from the volumes and freely 

traded. This approach places certain 

requirements on anyone who takes 

ownership of renewable fuels, including 

renewable fuel producers, importers, 

marketers, distributors, blenders, and 

terminal operators. 

a. Responsibilities of Renewable Fuel 

Producers and Importers 

The initial generation of RINs and 

their assignment to batches of renewable 

fuel will be the sole responsibility of 

renewable fuel producers and renewable 

fuel importers. As described in Section 

III.D.1, volumes of renewable fuel can 

be measured most accurately and be 

more readily verified at these 

originating locations. 

The final rule defines a batch of 

renewable fuel as a volume that has 

been assigned a unique batch-RIN. This 

simple and flexible definition of a batch 

allows renewable fuel producers and 

importers to construct each batch-RIN 

based on the particular circumstances 

associated with the batch. In this 

context, a batch is not confined to the 

volume that can be held in a tank, but 

instead can include a significantly larger 

volume. However, we are placing two 

limits on the volumes of renewable fuel 

that are identified as a single batch. 

First, the RIN contains only enough 

digits to permit the assignment of 

99,999,999 gallon-RINs to a single batch. 

For corn-ethanol with an Equivalence 

Value of 1.0, this means that a single 

batch can be comprised of up to 

99,999,999 gallons of ethanol. In 

contrast, for biodiesel with an 

Equivalence Value of 1.5, a single batch 

can contain up to 66,666,666 gallons of 

biodiesel. Second, in order to provide 

more clarity in the event that an 

investigation of a party’s volume and 

RIN generation records is conducted, we 

are also limiting a batch to the 

maximum volume that is produced or 

imported by the renewable fuel 

producer or importer within a calendar 

month. Within these two limits, 

producers and importers can define 

batches of renewable fuel according to 

their own discretion and practices, 

including using individual tankfulls to 

represent each batch. These parties must 

designate a unique serial number for 

each batch (RIN code BBBBB) and 

specify its Equivalence Value. The 

batch-RIN will identify all the gallonRINs assigned to the batch. See Section 

III.D.2.a for details on the format for 

RINs. 

In the NPRM, we proposed different 

approaches to the assignment of 

standard-value RINs and extra-value 

RINs. Under the proposal, extra-value 

RINs could be generated by the 

renewable fuel producer in cases where 

the renewable fuel in question had an 

Equivalence Value greater than 1.0. We 

proposed that all standard-value RINs 

must be assigned to volumes of 

renewable fuel, but that producers 

should have the option of whether to 

assign extra-value RINs to batches. We 

took this approach in part out of 

concern that the assignment of extravalue RINs to volumes would mean that 

the number of gallon-RINs assigned to a 

batch could be greater than the number 

of gallons in that batch. This was of 

particular concern for ethanol, since a 

tank could contain both corn-ethanol 

and cellulosic ethanol. When volume 

was withdrawn from the tank, it would 

have been unclear whether the volume 

should be assigned the extra-value RINs 

or not. In the process of designing the 

proposed program structure to 

accommodate such situations, however, 

the program became more complicated 

than it needed to be. 

In response to the NPRM, some 

commenters requested that extra-value 

RINs be treated just like standard-value 

RINs. Specifically, some obligated 

parties, as well as gasoline marketers 

and distributors, argued that all RINs, be 

they standard-value or extra-value, 

should be required to travel with 

volumes of renewable fuel so that they 

will all be equally available to the 

obligated parties that need them for 

compliance. These commenters 

expressed concern that some producers 

may not release extra-value RINs, if 

given the choice, in an effort to drive up 

demand for renewable fuel. 

After further consideration, we have 

determined that in most cases there is 

no need to treat extra-value RINs 

differently from standard-value RINs in 

terms of whether each should be 

assigned to batches of renewable fuel by 

the producer or importer. Therefore, for 

most renewable fuels we are finalizing 

a requirement that all RINs be assigned 

to batches of renewable fuel by the 

producer or importer. Since each 

renewable fuel with a different 

Equivalence Value is a distinct fuel, 

producers and importers will still 

receive the added value of extra-value 

RINs that are assigned to volumes of 

renewable fuel if those volumes are 

priced appropriately in comparison to 

other renewable fuels with different 

Equivalence Values. The only exception 

to this is cellulosic biomass and wastederived ethanol. Producers of such 

ethanol may have difficulty marketing 

their product at prices different than 

that for corn ethanol given the fungible 

distribution system for ethanol. The 

added value of the extra-value RINs may 

not be reflected in the price and as a 

result the producer may not receive any 

economic benefit from them. Therefore, 

for the case of cellulosic biomass and 

waste-derived ethanol we are 

maintaining the ability of the producer, 

should they so choose, to retain the 

extra value and not assign these RINs to 

the renewable fuel that they represent. 

In such cases, the producer of the 

cellulosic biomass or waste-derived 

ethanol would be required to change the 

K code from 1 to 2 in order to designate 

these extra RINs as separated RINs. 

This approach is also consistent with 

one of the primary motivations for the 

approach described in our NPRM, 

namely that each gallon-RIN be allowed 

to have a value of 1.0 to facilitate 

trading. Even though different 

renewable fuels will have different 

Equivalence Values and therefore 

different numbers of gallon-RINs per 

gallon, each gallon-RIN will still count 

as one gallon of renewable fuel for RFS 

compliance purposes. 

However, the distinction between 

standard-value RINs and extra-value 

RINs is no longer necessary. The total 

number of gallon-RINs that can be 

generated for a given batch of renewable 

fuel will be determined directly by its 

Equivalence Value as described in 

Section III.D.2.b, and all such gallonRINs will be summarized in a single 

batch-RIN assigned to a batch. In cases 

where the Equivalence Value is greater 

than 1.0, there will be more gallon-RINs 

assigned to a batch of renewable fuel 

than gallons in that batch. Once again, 

in the context of the changes we are 

making to the RIN distribution program 

structure as described in Section 

III.E.1.b below, we do not believe that 

this will in any way complicate the 

process of distributing RINs with 

renewable fuel. For the specific case of 

cellulosic biomass or waste-derived 

ethanol with an Equivalence Value of 

2.5, producers will be required to assign 

only one gallon-RIN to each gallon of 

ethanol, each of which has a K code 

value of 1. The additional 1.5 gallonRINs that can be generated for each 

gallon can remain unassigned, and thus 

be assigned a K code value of 2. 

In addition to cases where the 

Equivalence Value is greater than 1.0, 

there are several other cases in which 

the gallon-RINs assigned to a batch will 

not exactly correspond to the number of 

gallons in that batch. First, if a 

renewable fuel has an Equivalence 

Value less than 1.0, then there will be 

fewer gallon-RINs than gallons in the 

batch. Such potential circumstances are 

described in Section III.D.2.c. RINs may 

also not correspond exactly to gallons if 

the density of the batch changes due to 

changes in temperature. For instance, 


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37An appropriate temperature correction for 

other renewable fuels must likewise be used. 

38 Derived from ‘‘Fuel Ethanol Technical 

Information,’’ Archer Daniels Midland Company, 

v1.2, 2003. 

39 Derived from R.E. Tate et al., ‘‘The densities of 

three biodiesel fuels at temperatures up to 300 °C,’’ 

Fuel 85 (2006) 1004–1009, Table 1 for soy methyl 

ester. 

under extreme changes in temperature, 

the volume of a batch of ethanol can 

change by 5 percent or more. For this 

reason we are requiring that all batch 

volumes be corrected to represent a 

standard condition of 60 °F prior to the 

assignment of a RIN. For ethanol,37 we 

are requiring that the correction be done 

as follows:38

Vs,e = Va,e × (¥0.0006301 × T + 1.0378) 

Where: 

Vs,e = Standard volume of ethanol at 60 °F, in 

gallons. 

Va,e = Actual volume of ethanol, in gallons. 

T = Actual temperature of the batch, in °F. 

Since batches of ethanol are generally 

sold using standard volumes rather than 

actual volumes, this approach to 

assigning RINs to batches is consistent 

with current practices and will maintain 

the one-to-one correspondence between 

the volume block in the batch-RIN and 

the standardized volume of the batch. 

We are requiring a similar approach for 

biodiesel, where the volume correction 

must be calculated using the following 

equation:39

Vs,b = Va,b × (¥0.0008008 × T + 1.0480) 

Where: 

Vs,b = Standard volume of biodiesel at 60 °F, 

in gallons. 

Va,b = Actual volume of biodiesel, in gallons. 

T = Actual temperature of the batch, in °F. 

Consistent with the NPRM, we are 

requiring that RIN generation begin at 

the same time that the renewable fuel 

standard becomes applicable to 

obligated parties. Thus RINs must be 

generated for all renewable fuel 

produced or imported on or after 

September 1, 2007. Since many 

producers and importers will have 

renewable fuel in inventory at the start 

of the program that was produced prior 

to September 1, 2007, we are also 

allowing them to generate RINs for any 

renewable fuel that they own on 

September 1, 2007. This provision 

ensures that every gallon that a 

producer or importer sells starting on 

September 1, 2007 can have an assigned 

RIN, and obligated parties that take 

ownership of renewable fuel directly 

from a producer or importer will have 

greater assurance of receiving RINs at 

the start of the program. Since RINs are 

not assigned to volumes until those 

volumes are transferred to another 

party, this approach also provides 

producers and importers of renewable 

fuel the flexibility to determine which 

of the volumes they own on September 

1, 2007 constitute production as of the 

start of the program. 

Although a RIN is generated when 

renewable fuel is produced or imported, 

we do not define the point of 

production. However, the RIN must be 

assigned to a batch no later than the 

point in time when ownership of the 

batch is transferred from the producer or 

importer to another party. If ownership 

of the batch is retained by the producer 

or importer after the batch leaves the 

originating facility, the RIN need not be 

transferred along with the batch on 

product transfer documents identifying 

transfer of custody. 

The means through which RINs are 

transferred with volumes of renewable 

fuel will in some respects be left to the 

discretion of the renewable fuel 

producer or importer. The primary 

requirement would be that the RIN 

transfer be recorded on a product 

transfer document (PTD). The PTD can 

be included in any form of standard 

documentation that is already 

associated with or used to identify title 

to the volume or can be a separate 

document as described below. In many 

cases an invoice could serve this 

purpose. As in other fuels programs, we 

believe the PTD requirement can be met 

by including the required information 

generated and transferred in the normal 

course of business. 

RINs are transferable in the context of 

the RFS program and initially must be 

transferred along with ownership of a 

volume of renewable fuel. The approach 

that a producer or importer takes to the 

transfer or sale of RINs and volumes 

would be at their discretion, under the 

condition that the RIN and volume be 

transferred or sold on the same day and 

to the same party. Based on comments 

received, we are also permitting the 

transfer of RINs to be done in a separate 

PTD from the PTD used to transfer 

ownership of the volume of renewable 

fuel. This will provide some additional 

flexibility to parties who take ownership 

of renewable fuel with assigned RINs, 

permitting IT systems managing RIN 

transfers to be more easily incorporated 

into existing business management 

systems. Thus a party may use two 

separate PTDs, one for the volume and 

another for the RINs. However, transfer 

of the RINs must occur on the same day 

that transfer of the volume occurred, 

and the two PTDs must contain 

sufficient information to uniquely 

cross–reference them. In many cases an 

electronic transfer will suffice if 

sufficient information about the transfer 

is recorded. In the case of such parallel 

PTDs, we are also requiring that the PTD 

transferring ownership of the volume 

must indicate whether RINs are being 

transferred and the number of gallon– 

RINs being transferred, though it need 

not list the actual RINs. 

As described in Section III.E.1.b 

below, while assigned RINs must always 

be transferred to another party with a 

volume of renewable fuel, we are 

allowing any party that received 

assigned RINs with renewable fuel to 

thereafter transfer anywhere from zero 

to 2.5 gallon-RINs with each gallon of 

renewable fuel. This provision provides 

the flexibility to transfer more assigned 

RINs with some volumes and less 

assigned RINs with other volumes 

depending on the business 

circumstances of the transaction and the 

number of RINs that the seller has 

available. However, for producers and 

importers of renewable fuel, this level of 

flexibility could contribute to short-term 

hoarding that was the primary concern 

expressed by obligated parties during 

development of the proposed program. 

Therefore we are also finalizing a 

provision that requires producers and 

importers to transfer assigned gallonRINs with gallons such that the ratio of 

assigned gallon-RINs to gallons is equal 

to the equivalence value for the 

renewable fuel. Since this is not 

possible for exempt small volume 

producers, or when a producer or 

importer obtains renewable fuel from 

another party without assigned RINs, 

exceptions are made in these cases. 

We received comment that EPA 

should require a purchaser of imported 

gasoline who subsequently blends 

renewable fuel into the imported 

gasoline to transfer the RINs associated 

with the renewable fuel back to the 

importer of the gasoline. The 

commenter suggested that this 

requirement would ensure that the 

importer of the gasoline obtains all the 

RINs associated with the renewable fuel 

blended into that gasoline in cases 

where the importer has a long-term 

contractual agreement with the party 

that purchases the gasoline and adds the 

renewable fuel. However, we do not 

believe that such a provision is 

warranted. The RFS program places the 

renewable fuels obligation on parties 

based on ownership of the gasoline at 

the refiner or importer level. We believe 

this approach is the most effective way 

to implement and enforce the renewable 

fuels requirement. We also believe it is 

appropriate to allow parties who add 

the renewable fuel to gasoline, 

including blenders, to separate RINs 

from the renewable fuel volume and to 

have the right to sell those RINs to any 

party. Individual parties may agree that, 


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in certain situations, it would be 

appropriate for the RINs to be 

transferred from the renewable fuels 

blender to the importer of the gasoline. 

In such cases, the parties may make 

contractual arrangements for the 

transfers. We do not believe it would be 

appropriate or workable for EPA to 

require such transfers. 

The NPRM did not specify whether 

RINs should be generated for and 

assigned to renewable fuel that is 

already contained in imported gasoline 

(for example, a blend of 10 percent 

ethanol and 90 percent gasoline). Since 

the renewable fuel contained in 

imported gasoline is part of the total 

volume of renewable fuel in gasoline 

sold or introduced into commerce in the 

U.S., we believe it is appropriate to treat 

it as any other imported renewable fuel. 

Thus, we believe it would be 

appropriate for importers to assign RINs 

to renewable fuel contained in imported 

gasoline. However, the volume of 

renewable fuel contained in imported 

gasoline is very small in comparison to 

the volume requirements of the RFS 

program. If an importer of gasoline 

containing renewable fuel imports less 

than 10,000 gallons per year of 

renewable fuel, then that party is not 

required to generate RINs. But a small 

volume importer that chooses to 

generate and assign RINs to any volume 

of renewable fuel in imported gasoline 

is required to fulfill all of the 

requirements that apply to renewable 

fuel importers under the RFS rule, in 

addition to all of the requirements that 

apply to gasoline importers as obligated 

parties. An importer that assigns RINs to 

the renewable fuel in imported gasoline 

may separate the RINs from the 

renewable fuel, since the renewable fuel 

has been blended into gasoline. 

Regardless of a small volume 

importer’s decision to generate and 

assign RINs to renewable fuel contained 

in imported gasoline, an importer that 

imports any gasoline containing 

renewable fuel must include the 

gasoline portion of the imported 

product in the volume used to 

determine the importer’s renewable fuel 

obligation (and exclude the renewable 

fuel portion of the batch). RINs must be 

assigned to imported renewable fuels 

that are not contained in gasoline at the 

time of importation, unless less than 

10,000 gallons of renewable fuel are 

imported per year. 

b. Responsibilities of Parties That Buy, 

Sell, or Handle Renewable Fuels 

Volumes of renewable fuel can be 

transferred between many different 

types of parties as they make their way 

from the production or import facilities 

where they originated to the places 

where they are blended into 

conventional gasoline or diesel. Some of 

these parties take custody but not 

ownership of these volumes, storing and 

transmitting them on behalf of those 

who retain ownership. Other parties 

take ownership but not custody, such as 

a refiner who purchases ethanol and has 

it delivered directly to a blending 

facility. Thus prior to blending, each 

volume of renewable fuel can be owned 

or held by any number of parties 

including marketers, distributors, 

terminal operators, and refiners. 

In the NPRM, we proposed that in 

general all parties that assume 

ownership of any volume of renewable 

fuel would be required to transfer all 

RINs assigned to that volume to another 

party to whom ownership of the volume 

is being transferred. The only 

exceptions to the requirement that RINs 

be transferred with volumes would be 

for parties who are obligated to meet the 

renewable fuel standard and parties 

who convert the renewable fuel into 

motor vehicle fuel. Commenters 

overwhelmingly supported this 

approach to the distribution of RINs 

assigned to volumes of renewable fuel, 

and as a result we are adopting this 

approach in our final program. In this 

context, we are also clarifying that 

parties taking custody of a volume of 

renewable fuel but not ownership of 

that volume would have no 

responsibilities with regard to the 

transfer of RINs. 

However, in response to the NPRM, 

several stakeholders apprised us of 

certain aspects of our proposed program 

that would limit the intended 

fungibility of RINs assigned to volumes 

of renewable fuel. While the goal of our 

proposed program was to permit RINs to 

be interchangeable with one another 

and to permit one assigned RIN to be 

exchanged with another RIN, our 

proposed regulations did not 

sufficiently capture this level of 

fungibility. Instead, the proposed 

regulations effectively required that a 

specific RIN assigned to a specific 

gallon of renewable fuel must remain 

assigned to that specific gallon as it 

travels through the distribution system. 

This approach was taken in order to 

accommodate the legitimate existence of 

some volumes of renewable fuel without 

assigned RINs, and some assigned RINs 

that have no corresponding volume. 

These situations can occur in the 

distribution system for several reasons, 

such as the following: 

• RINs can be separated from 

renewable fuel by obligated parties or 

blenders, and the renewable fuel reintroduced into the distribution system. 

• Small volume producers are exempt 

from generating and assigning RINs to 

their product. 

• At the start of the program, some 

parties may have renewable fuel in their 

inventories that have not been assigned 

a RIN. 

• Batches of renewable fuels with 

Equivalence Values less than 1.0 will 

have fewer gallon-RINs than gallons. 

• Batch volumes can swell or shrink 

due to temperature changes. 

• Batch volumes can shrink due to 

evaporation, spillage, leakage, or 

accidents. 

• Volume metering imprecision. 

Indeed, if the program could be 

designed such that every gallon in the 

distribution system always had an 

assigned RIN, the complete fungibility 

of RINs would be straightforward. 

However, this is not the case. 

In order to make assigned RINs more 

fungible, we are finalizing a modified 

version of our proposed approach. 

Consistent with the NPRM, no party 

will be permitted to change a RIN 

assigned to a volume of renewable fuel 

into an unassigned (separated) RIN 

except for those parties explicitly given 

the right to do so (for example, obligated 

parties and oxygenate blenders). Also 

consistent with the NPRM, any party 

not authorized to separate an assigned 

RIN that takes ownership of a RIN 

assigned to a volume of renewable fuel 

cannot transfer ownership of that RIN to 

another party without simultaneously 

transferring an appropriate volume of 

renewable fuel. 

However our final regulations allow 

any party to transfer a volume of 

renewable fuel without assigned RINs, 

or with a different number of assigned 

RINs than were received with the 

renewable fuel, as long as the number of 

assigned gallon-RINs held by that party 

at the end of a quarter is no higher than 

the number of gallons it owns at the end 

of the quarter. This will provide parties 

with the flexibility to decide which 

RINs are transferred with which 

volumes, and to transfer some volumes 

without RINs if the party took 

ownership of some volumes without 

assigned RINs. Our final regulations 

require only that the number of gallonRINs held by a party at the end of a 

quarter be no higher than the number of 

gallons held by that party, adjusted by 

their Equivalence Value. Aside from 

spillage, evaporation, or volume 

metering imprecision, the only way that 

the number of gallon-RINs that are held 

by a party could be higher than the 

number of gallons held (adjusted for 

their Equivalence Value) is if that party 

transferred some volume without RINs. 

In such a case the excess RINs held 


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would be deemed to have been 

separated from renewable fuel, in 

violation of the prohibition against 

separating RINs. 

While this approach creates more 

flexibility for parties that hold assigned 

RINs, it requires three additional 

changes to the proposed regulations. 

First, we are requiring parties that hold 

assigned RINs to also report the volumes 

of renewable fuel held at the end of each 

quarter. While the NPRM did not 

propose that volumes held be reported, 

we believe that the additional burden on 

parties holding assigned RINs will be 

minimal. The NPRM proposed that the 

recordkeeping requirements include 

information on all renewable fuel 

volumes transferred, so under the 

proposal parties holding assigned RINs 

would in general already have the 

information available. In addition, we 

are not requiring that all volumes held 

at any time during the quarter be 

reported, nor are we requiring that all 

volumes transferred be reported. Rather, 

parties will be required only to report 

the total volume of renewable fuel and 

the total number of gallon-RINs held on 

the last day of a quarter, in addition to 

other information regarding RINs held 

and transferred. 

Second, our modified approach 

requires that we distinguish between 

RINs assigned to renewable fuel and 

RINs that have already been separated 

from renewable fuel, since only 

assigned RINs would be subject to the 

end-of-quarter comparison of RINs held 

and volumes held. We have chosen to 

use the K code in the RIN for this 

purpose, since it no longer serves the 

purpose of distinguishing between 

standard-value and extra-value RINs. 

The K code has also been moved to the 

beginning of the RIN to make its value 

more prominent. RINs assigned to 

renewable fuel must have a K code of 

1. Parties who legally separate a RIN 

from renewable fuel must change the K 

code for that RIN to a value of 2. The 

RIN then formally becomes an 

unassigned RIN that can be transferred 

independent of renewable fuel volumes. 

The end-of-quarter comparisons 

between RINs held and volumes held 

apply only to RINs with a K value of 1. 

Third, we are requiring quarterly 

reporting in addition to annual reports 

for RINs held and transferred. In the 

NPRM we took comment on requiring 

quarterly reporting for various reasons. 

We received both comments supporting 

and opposing quarterly reporting. As 

discussed further in Section IV, we are 

requiring quarterly reporting in this 

final rule. Under our modified program 

structure, quarterly reporting will be 

necessary to ensure that RINs are 

available for obligated parties’ annual 

compliance. Quarterly reports will 

provide us with the ability to monitor 

the activities of marketers and 

distributors in real time to ensure that 

they are transferring RINs with 

renewable fuel, and to address potential 

violations as soon as they arise. 

As discussed in Section III.E.1.a 

above, we are requiring that producers 

and importers of renewable fuel assign 

all RINs to volumes of renewable fuel, 

consistent with our proposed approach 

to standard-value RINs. As a result, 

downstream parties can legitimately 

hold more gallon-RINs than gallons if 

some of the renewable fuel has an 

Equivalence Value greater than 1.0. In 

the context of our modified approach to 

RIN distribution, this fact must be taken 

into account in the end-of-quarter 

comparison of gallon-RINs held and 

gallons held. Thus the following 

equation must be satisfied at the end of 

each quarter by each party that has 

taken ownership of any assigned RINs: 

S(RIN)D ≤ S(Vsi×EVi)D

Where: 

D = Last day of a quarter (Jan–Mar, Apr–Jun, 

Jul–Sep, Oct–Dec). 

S(RIN)D = Sum of all assigned gallon-RINs 

with a K code of 1 that are owned on the 

last day of the quarter. 

(Vsi)D = Volume i of renewable fuel owned on 

the last day of the quarter, standardized 

to 60 °F, in gallons. 

EVi = Equivalence Value representing volume 

i. 

S(Vsi×EVi)D = Sum of all volumes of 

renewable fuel owned on the last day of 

the quarter, multiplied by their 

respective equivalence values. 

Under our fungible distribution 

system, the RINs received with a 

volume of renewable fuel may not be 

the RINs originally generated to 

represent that particular volume. Thus 

the Equivalence Value for a volume of 

renewable fuel cannot be based on the 

RR code of associated RINs, but instead 

should be determined from the 

composition of the renewable fuel. If the 

Equivalence Value for a volume of 

renewable fuel cannot be determined 

from its composition, it should be 

assumed to be 1.0. However, in the 

specific case of ethanol the owner may 

not know if a volume can be categorized 

as cellulosic biomass ethanol or wastederived ethanol. Thus for volumes of 

ethanol held at the end of a quarter, the 

Equivalence Value should be assumed 

to be 2.5 to ensure that a party can 

legitimately hold more RINs than 

gallons. 

The above equation ensures that the 

total number of gallon-RINs that can be 

held by a party at the end of a quarter 

is no greater than the number of gallonRINs he could have received given the 

volume of renewable fuel that he owns. 

Parties that do not satisfy the above 

equation are deemed to be in violation 

of the prohibition against separating 

RINs from volumes. 

Under our modified approach to RIN 

distribution, it might be possible for a 

party who owns volumes of renewable 

fuel with assigned RINs to hold onto all 

the RINs until near the end of a quarter 

while selling volume without RINs. 

Then, in order to comply with the above 

equation, the party could transfer all 

assigned RINs with a single volume of 

renewable fuel prior to the last day of 

the quarter. This approach would 

amount to short-term hoarding. To 

prevent it, we are also placing a cap on 

the maximum number of gallon-RINs 

that can be transferred with any gallon 

of renewable fuel. The cap is dictated by 

the maximum number of gallon-RINs 

that a party could receive with a volume 

of renewable fuel, which is 2.5 in the 

case of cellulosic biomass ethanol or 

waste-derived ethanol. For a party that 

took ownership of these types of 

renewable fuel, we must allow them to 

transfer up to 2.5 gallon-RINs with each 

gallon. 

We are also aware that there are 

situations in which the volume 

transferred to another party might be 

smaller than the volume originally 

received. This could occur due to fuel 

evaporation, spillage, leakage, or 

volume metering imprecision, and 

would have the effect of raising the ratio 

of gallon-RINs held to gallons held. For 

spillage/leakage involving significant 

volumes, we have developed a 

mechanism for formally retiring the 

RINs associated with the lost volume. 

See Section IV. Smaller volume losses 

can be accommodated by a RIN transfer 

cap of 2.5, which would in general 

allow RINs associated with lost volume 

to be transferred with remaining 

volume. In the rare case that a party 

takes ownership of only cellulosic 

biomass ethanol or waste-derived 

ethanol and experiences some small 

volume loss, he can take ownership of 

a small volume of some other form of 

renewable fuel with an Equivalence 

Value less than 2.5. This will permit 

him to transfer RINs associated with lost 

volume to another party while still 

meeting the RIN transfer cap of 2.5. 

Our program is designed to allow RIN 

transfer and documentation to occur as 

part of normal business practices in the 

context of renewable fuel distribution. 

Thus the incremental costs of 

transferring RINs with volumes is 

expected to be minimal. Marketers and 

distributors must simply add the RIN to 

product transfer documents such as 


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invoices, and record the RINs in their 

records of volume purchases and sales. 

Finally, the final rule also provides 

that a foreign entity may apply to EPA 

for approval to own RINs. As an 

approved foreign RIN owner, the foreign 

entity will be able to obtain, sell, 

transfer and hold both assigned and 

separated RINs. An approved foreign 

RIN owner will be required to comply 

with all requirements that apply to 

domestic RIN owners under the RFS 

rule. In addition, similar to other fuels 

programs, an approved foreign RIN 

owner will be required to comply with 

additional requirements designed to 

ensure that enforcement of the RFS 

regulations at the foreign RIN owner’s 

place of business will not be 

compromised. 

c. Batch Splits and Batch Mergers 

In the RIN distribution approach 

proposed in the NPRM, RINs assigned to 

a given volume of renewable fuel 

remained assigned to that volume as it 

moved through the distribution system. 

In that context, batch splits and batch 

mergers required special treatment. We 

discussed the need for protocols to 

ensure that RINs assigned to parent 

batches were appropriately distributed 

among daughter batches, and that RINs 

assigned to batches that were merged 

were all re-assigned to the new 

combined batch. The proposed 

regulations included some restrictions 

on how parent batch RINs were to be 

apportioned to daughter batches during 

splits, but fell short of prescribing a 

detailed batch split protocol. 

Nevertheless, commenters by and large 

did not address these protocols in their 

comments. 

The need for protocols for batch splits 

and batch mergers was directly related 

to the NPRM’s approach to the 

distribution of RINs with volumes of 

renewable fuel. As described in Section 

III.E.1.b above, we are modifying our 

approach to permit assigned RINs to be 

more fungible. As a result, there is no 

need for the regulations to specify any 

batch splitting or batch merging 

protocols. 

Under our final regulations, parties 

taking ownership of volumes of 

renewable fuel with assigned RINs will 

simply retain an inventory of all 

assigned RINs owned. As volumes of 

renewable fuel are then transferred to 

other parties, an appropriate number of 

gallon-RINs are withdrawn from the 

party’s inventory and transferred along 

with the renewable fuel. There is no 

need for the party to determine which 

RINs were originally assigned to the 

volume being transferred. For parties 

handling both ethanol and biodiesel, it 

would be reasonable to transfer RINs 

with volumes in a manner consistent 

with the Equivalence Value of the 

renewable fuel, but this would not be 

required under our final regulations in 

which the number of assigned gallonRINs transferred with each gallon of 

renewable fuel can be anywhere 

between zero and 2.5. In addition, 

volumes of renewable fuel can be split 

or merged any number of times while 

remaining under the ownership of a 

single party, with no impact on RINs. It 

is only when ownership of a volume of 

renewable is transferred to another party 

that an appropriate number of gallonRINs need to be withdrawn from the 

party’s inventory and assigned to the 

transferred volume, subject to the 

flexibility associated with the quarterly 

average as discussed above. 

2. Separation of RINs From Volumes of 

Renewable Fuel 

Separation of a RIN from a volume of 

renewable fuel means that the RIN is no 

longer included on the PTD and can be 

traded independently from the volume 

to which it had originally been assigned. 

In general commenters supported our 

proposed approach of limiting the 

parties that can separate a RIN from a 

batch, and the associated conditions 

under which separation can occur. 

In designing the regulatory program, 

we structured it around facilitating 

compliance by obligated parties with 

their renewable fuel obligation, with the 

intention of giving obligated parties the 

power to market the renewable fuel 

separately from the RIN originally 

assigned to it. Our final program 

therefore requires a refiner or importer 

to separate the RIN from renewable fuel 

as soon as he assumes ownership of that 

renewable fuel. In the case of ethanol 

blended into gasoline at low 

concentrations (≤ 10 volume percent), 

stakeholders have informed us that a 

large volume of the ethanol is purchased 

by refiners directly from ethanol 

producers, and is then passed to 

blenders who carry out the blending 

with gasoline. Therefore, in many cases 

RINs assigned to renewable fuel will 

pass directly from the producers who 

generated them to the obligated parties 

who need them. 

However, significant volumes of 

ethanol are also blended into gasoline 

without first being purchased by a 

refiner. In some cases, the blender itself 

purchases the ethanol. In other cases, a 

downstream customer purchases the 

ethanol and contracts with the blender 

to carry out the blending. Regardless, 

the ethanol may never be held or owned 

by an obligated party before it is 

blended into gasoline. Thus we are also 

requiring a blender to separate the RIN 

from the renewable fuel if he takes 

ownership of the renewable fuel and 

actually blends it into gasoline (or, in 

the case of biodiesel, into diesel fuel). 

This would only apply to volumes 

where the RIN had not already been 

separated by an obligated party. Since 

blenders will in general not be obligated 

parties under our program, blenders 

who separate RINs from renewable fuel 

will have no need to hold onto those 

RINs and thus can transfer them to an 

obligated party for compliance purposes 

or to any other party. 

There may be occasions in which a 

retailer downstream of a blender 

actually owns the volume of renewable 

fuel when it is blended into gasoline or 

diesel. In such cases the blender will 

have custody but not ownership of the 

renewable fuel. In today’s final rule we 

are requiring the RIN to be separated 

from the volume of renewable fuel when 

that volume is blended into gasoline, 

but the RIN can only be separated by the 

party that owns that volume of 

renewable fuel at the time of blending. 

In the case of a blender and a 

downstream customer who might both 

lay claim to the right to separate any 

assigned RINs (for instance, if transfer of 

ownership occurred simultaneous with 

blending), these two parties would need 

to come to agreement between 

themselves regarding which party will 

own the separated RINs. 

As described in Section III.B, many 

different types of renewable fuel can be 

used to meet the RFS volume 

obligations placed upon refineries and 

importers. Currently, ethanol is the most 

prominent renewable fuel and is most 

commonly used as a low level blend in 

gasoline at concentrations of 10 volume 

percent or less. However, some 

renewable fuels can be used in neat 

form (i.e. not blended with conventional 

gasoline or diesel). The two RIN 

separation situations described above 

would capture any renewable fuel for 

which ownership is assumed by an 

obligated party or a party that blends the 

renewable fuel into gasoline or diesel. 

However, renewable fuels which are 

used in their neat (unblended) form as 

motor vehicle fuel would not be 

captured. This would include such 

renewable fuels as neat biodiesel (B100) 

or renewable diesel, methanol for use in 

a dedicated methanol vehicle or biogas 

for use in a CNG vehicle. 

Under our final program, producers 

and importers must assign a RIN to all 

renewable fuels produced or imported, 

including neat renewable fuels. To 

avoid the possibility that the RIN 

assigned to neat renewable fuel would 

never become available to an obligated 


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40Throughout this Section III.E.2, ‘‘biodiesel’’ 

means mono alkyl esters, not non-ester renewable 

diesel. 

party for RFS compliance purposes, in 

the NPRM we proposed to more broadly 

define the right to separate a RIN from 

renewable fuel. In addition to obligated 

parties and blenders, we proposed that 

any producer holding a volume of 

renewable fuel for which the RIN has 

not been separated could separate the 

RIN from that volume if the party 

designates it for use only as a motor 

vehicle fuel in its neat form and it is in 

fact only used as such. This approach 

would recognize that the neat form of 

the renewable fuel is valid for 

compliance purposes under the RFS 

program, as described in Section III.B. 

In effect, it would place neat fuel 

producers in the same category as 

blenders, in that they are producing 

motor vehicle fuel. We did not receive 

any negative comments on this 

proposal, and thus are finalizing this 

provision as proposed. 

As discussed above, under our final 

rule, obligated parties must separate 

RINs from volumes of renewable fuel. 

This applies to all volumes of renewable 

fuel that an obligated party owns. The 

requirement to separate a RIN from the 

renewable fuel is intended to apply to 

refiners, blenders and importers for 

whom the production or importation of 

gasoline is a significant part of their 

overall business operations. Parties that 

are predominately renewable fuel 

producers or importers, but which must 

be designated as obligated parties due to 

the production or importation of a small 

amount of gasoline, should not be able 

to separate RINs from all renewable 

fuels that they own. For example, we 

believe it would be inappropriate to 

permit an ethanol producer to separate 

RINs from all volumes that they own 

simply because the producer imported, 

for example, a single truckload of 

gasoline from Canada or Mexico. As a 

result, the final rule prohibits obligated 

parties from separating RINs from 

volumes of renewable fuel that they 

produce or import that are in excess of 

their RVO. However, obligated parties 

must separate any RINs from volumes of 

renewable fuel that they own if that 

volume was produced or imported by 

another party. 

As described in Section III.B.2, RINs 

can be generated for renewable fuels 

made from renewable crude which is 

treated as if it were a petroleum-derived 

crude oil or derivative, and is used as 

a feedstock in a traditional refinery 

processing unit. Whether the renewable 

crude is coprocessed with petroleum 

derivatives or is processed in a facility 

or unit dedicated to the renewable 

crude, the final product is generally a 

motor vehicle fuel. In such cases the 

refinery will have the responsibility of 

generating RINs for the renewable fuel 

produced. But since renewable crude is 

generally processed in a traditional 

refinery, the refiner will be an obligated 

party and can therefore immediately 

separate those RINs from the renewable 

fuel and transfer them to another party. 

As described in III.E.1.a above, 

cellulosic and waste-derived ethanol 

producers will also be permitted to 

separate the RINs associated with the 

extra 1.5 value of their ethanol 

production. 

Once a RIN is separated from a 

volume of renewable fuel, the PTD 

associated with that volume can no 

longer list the RIN. However, in the 

NPRM we requested comment on 

whether PTDs should include some 

notation indicating that the assigned 

RIN has been removed to avoid 

concerns about whether RINs assigned 

to batches have not been appropriately 

transferred with the batch. One refiner 

commented that the addition of such a 

note on a PTD would represent an 

unnecessary burden, while two 

commenters representing fuel 

distribution operations indicated that 

such a notation would be useful. Based 

on comments we received, we have 

determined that such notation on PTDs 

would not only be useful to parties 

receiving volumes of renewable fuel, but 

would also be an important element of 

our RIN distribution requirements under 

our modified approach. The 

requirement will ensure that parties 

who take ownership of renewable fuel 

without assigned RINs will know that 

RINs were originally assigned but 

subsequently removed. We also believe 

that such a requirement would be of 

minimal burden to parties that have 

separated a RIN from a volume of 

renewable fuel. 

As described in Section III.E.1.b, we 

have modified the RIN transfer 

requirements for the final rule to make 

RINs more fungible and to provide more 

flexibility to distributors while still 

requiring RINs to be transferred with 

volumes of renewable fuel. However, 

our modified approach requires that we 

distinguish between RINs assigned to 

renewable fuel and RINs that have 

already been separated from renewable 

fuel. Our final rule thus requires that 

parties who separate a RIN from 

renewable fuel must change the K code 

for that RIN to a value of 2. The RIN 

then becomes an unassigned RIN that 

can be transferred independent of 

renewable fuel volumes. 

In the NPRM we also provided a 

discussion of the unique circumstances 

regarding biodiesel (mono alkyl 

esters) 40 and the conditions under 

which we believed a RIN should be 

separated from a volume of such 

biodiesel. As described in the proposal, 

biodiesel is one type of renewable fuel 

that can under certain conditions be 

used in its neat form. However, in the 

vast majority of cases it is blended with 

conventional diesel fuel before use, 

typically in concentrations of 20 volume 

percent or less. This approach is taken 

for a variety of reasons, such as to 

reduce impacts on fuel economy, to 

mitigate cold temperature operability 

issues, to address concerns of some 

engine owners or manufacturers 

regarding the impacts of biodiesel on 

engine durability or drivability, or to 

reduce the cost of the resulting fuel. 

Biodiesel (mono alkyl esters) is also 

used in low concentrations as a lubricity 

additive and as a means for complying 

with the ultra-low sulfur requirements 

for highway diesel fuel. Biodiesel (mono 

alkyl esters) is occasionally used in its 

neat form. However, this approach is the 

exception rather than the rule. 

Consequently, in the NPRM we 

proposed that the RIN assigned to a 

volume of biodiesel could only be 

separated from that volume if and when 

the biodiesel was blended with 

conventional diesel. To avoid claims 

that very high concentrations of 

biodiesel count as a blended product, 

we also proposed that biodiesel must be 

blended into conventional diesel at a 

concentration of 80 volume percent or 

less before the RIN could be separated 

from the volume. 

A number of commenters expressed 

concern that the 80 volume percent 

limit put biodiesel at odds with the RIN 

separation criteria applicable to other 

renewable fuels, including neat fuels. 

Upon further consideration, we have 

determined that the 80 volume percent 

limit remains a valid means for ensuring 

that the separation of RINs from 

biodiesel is consistent with its common 

use at low blend levels just as for 

ethanol, and that RINs are generally 

separated at the point in time when the 

biodiesel can be deemed to be motor 

vehicle fuel. However, based on 

comments received, we are changing the 

treatment of biodiesel for the final rule 

in two ways. 

First, obligated parties are required to 

separate RINs from volumes of biodiesel 

at the point when they gain ownership 

of the biodiesel, not when they blend 

biodiesel with conventional diesel fuel. 

This approach is consistent with our 

treatment of the RIN separation 


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requirements for obligated parties for 

other renewable fuels. Parties that 

actually blend biodiesel into 

conventional diesel fuel at a 

concentration of 80 volume percent or 

less would continue to be required to 

separate the RIN from the biodiesel, as 

proposed. 

Second, we have determined that a 

biodiesel producer should be allowed to 

separate a RIN from a volume of 

biodiesel that it produces if it designates 

the volume of biodiesel specifically for 

use as motor vehicle fuel in its neat 

form, and the neat biodiesel is in fact 

used as motor vehicle fuel. In general 

this demonstration would require that 

the producer track the volume of 

biodiesel to the point of its final use. 

However, this approach to the treatment 

of neat biodiesel is consistent with how 

we are treating other renewable fuels 

used in their neat form. 

3. Distribution of Separated RINs 

In the NPRM, we proposed that RINs 

become freely transferable once they are 

separated from a batch of renewable 

fuel. Each RIN could be held by any 

party and transferred between parties 

any number of times. We argued that the 

unique features of the RFS program 

warranted more open trading than in 

past fuel credit programs. In particular, 

RINs are generated by parties other than 

obligated parties, and many 

nonobligated parties will own RINs (for 

example, oxygenate blenders who have 

the right to separate RINs from 

volumes). While recognizing that 

limiting trading to and between 

obligated parties might help obligated 

parties to maintain control of those RINs 

being traded, such an approach could 

have the unintended effect of limiting 

the number of RINs that non-obligated 

parties contribute to the RIN market. 

The RFS program must work efficiently 

not only for a limited number of 

obligated parties, but a number of nonobligated parties as well. 

There was disagreement among 

commenters about whether an open RIN 

market was appropriate. Several parties 

supported our proposed approach, 

saying that unlimited trading among all 

interested parties would increase 

liquidity and transparency in the RIN 

market. They also argued that increasing 

the number of participants would 

facilitate the acquisition of RINs by 

obligated parties and promote economic 

efficiency. 

However, some commenters 

disagreed, arguing instead that an open 

market does not necessarily make the 

market any more fluid and free. They 

pointed to past credit programs in 

which only refiners and importers have 

been allowed to transfer credits, and 

argued that the success of those 

programs should compel the Agency to 

use those past credit program structures 

as the model for the RFS program. 

We continue to believe that there is a 

need to provide for more open trading 

in the RFS program and that this need 

warrants a unique approach for this 

rule. First, unlike other programs where 

credits generally represent 

overcompliance with an applicable 

standard and are thus supplemental to 

the means of compliance, under the RFS 

program RINs are the fundamental unit 

for compliance. There will be many 

more RINs in the RFS program than 

credits in other programs, and the 

trading structure must maximize the 

fluidity of those RINs. A wider RIN 

market will make it easier for obligated 

parties to get access to RINs. 

Second, obligated parties are typically 

not the ones producing the renewable 

fuels and generating the RINs, nor 

blending the renewable fuels into 

gasoline, so there is a need for trades to 

occur between obligated parties and 

non-obligated parties. If we prohibited 

everyone except obligated parties from 

holding RINs after they have been 

separated from a batch, non-obligated 

parties seeking avenues for releasing 

their RINs would only be able to release 

them to obligated parties. Having fewer 

avenues through which they could 

market their RINs, some non-obligated 

parties might opt not to transfer their 

RINs at all rather than participate in the 

RIN market with the attendant 

recordkeeping requirements. 

Furthermore, a potentially large number 

of oxygenate blenders, many of which 

will be small businesses, will be looking 

for ways to market their RINs. Allowing 

other parties, including brokers, to own 

and transfer RINs may create a more 

fluid and free market that would 

increase the venues for RINs to be 

acquired by the obligated parties that 

need them. Limiting RIN trading to and 

among obligated parties could make it 

more difficult for RINs to eventually be 

transferred to the obligated parties that 

need them. 

Some commenters argued that 

limiting the RIN trading market to and 

among obligated parties would make the 

program more enforceable, since there 

would be fewer parties to track and the 

sources of RINs would be more reliable. 

While this may be directionally true, we 

believe the RFS program will remain 

sufficiently enforceable under an open 

RIN market, and as discussed above, the 

greater need for market fluidity for this 

program warrants the change. The RIN 

number, along with the associated 

electronic reporting mechanism, will 

provide us the ability to verify the 

validity of RINs and the source of any 

invalid RINs. Since all RINs generated, 

traded, and used for compliance would 

be recorded electronically in an Agency 

database, these types of investigations 

should be straightforward. The number 

of RIN trades, and the parties between 

whom the RINs are being traded, will 

only have the effect of increasing the 

size of the database. 

Some commenters were concerned 

that an open RIN market could lead to 

price volatility and potentially higher 

prices as non-obligated speculators 

enter the market expressly to profit from 

the sale of RINs. According to 

commenters, these speculators would 

hold an unfair advantage over obligated 

parties that must purchase credits for 

compliance since speculators can hold 

onto RINs indefinitely, driving up their 

price. However, by expanding the 

number of parties that can hold RINs, 

we minimize the potential for any one 

party to exercise market power, and 

thus we do not believe that such activity 

on the part of speculators is likely to 

substantively affect the availability of 

RINs or their price. Moreover, we do not 

believe that a given party will hold a 

RIN indefinitely simply to increase 

profit because RINs have a limited life 

and new RINs will be generated and 

will enter the market continuously. 

Based on our review of the comments 

received, we did not find compelling 

evidence that an open market for RINs 

would create particular difficulties for 

obligated parties seeking RINs or would 

limit the enforceability of the program. 

As a result we are finalizing a RIN 

trading program that permits any party 

to hold RINs and for RINs to be traded 

any number of times. 

As with other credit-trading programs, 

the business details of RIN transactions, 

such as the conditions of a sale or any 

other transfer, RIN price, role of 

mediators, etc. will be at the discretion 

of the parties involved. The Agency is 

concerned only with information such 

as who holds a given RIN at any given 

moment, when transfers of RINs occur, 

who the party to the transfers are, and 

ultimately which obligated party relies 

on a given RIN for compliance purposes. 

This type of information will therefore 

be the subject of various recordkeeping 

and reporting requirements as described 

in Section IV, and these requirements 

will generally apply regardless of 

whether a RIN has been separated from 

a batch. 

The means through which RIN trades 

occur will also be at the discretion of 

the parties involved. For instance, 

parties with RINs can create open 

auctions, contract directly with those 


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obligated parties who seek RINs, use 

brokers to identify potential transferees 

and negotiate terms, or just transfer the 

RINs to any other party. Brokers 

involved in RIN transfer can either 

operate in the role of arbitrator without 

owning the RINs, or alternatively can 

take custody of the RINs from one party 

and transfer them to another. If they are 

the transferee of any RINs, they will also 

be subject to the registration, 

recordkeeping, and reporting 

requirements. The Agency will not be 

directly involved in RIN transfers, other 

than in the role of providing a database 

within which transfers will be recorded 

for enforcement purposes. 

In order to provide public information 

that could be helpful in managing and 

trading RINs as well as understanding 

how the program is operating, we intend 

to publish a report each year that 

summarizes information submitted to us 

through the quarterly and annual 

reports required as part of our 

enforcement efforts (see Section IV). 

Annual summary reports published by 

EPA may include such information as 

the number of RINs generated in each 

month or in each state, the average 

number of trades that RINs undergo 

before being used for compliance 

purposes, or the frequency of deficit 

carryovers. However, we will not 

publish information identifying specific 

parties. 

4. Alternative Approaches to RIN 

Distribution 

In the NPRM, we also described 

several alternative approaches to the 

proposed trading and compliance 

program that were offered by 

stakeholders. Most of these alternatives 

recognized the value of a RIN-based 

system of compliance, but they differed 

in terms of which parties would be 

allowed to separate a RIN from a batch 

and the means through which the RINs 

would be transferred to obligated 

parties. We invited comment on all of 

these alternatives in the NPRM, but 

received very few. Based on those 

comments we did receive, we do not 

believe that any of these alternative 

approaches should be implemented at 

this time. In general our responses to 

comments on the alternatives can be 

found in the Summary and Analysis of 

Comments document in the docket, but 

we have addressed one particular 

subject area below. 

In the NPRM, we described an 

alternative approach to RIN distribution 

in which obligated parties would only 

be able to separate a RIN from a batch 

of renewable fuel at the point in time 

when blending actually occurs. In 

contrast, the approach we are finalizing 

today requires an obligated party to 

separate a RIN from a batch as soon as 

it gains ownership of that batch. Our 

final program design is based on the 

expectation that all but a negligible 

quantity of renewable fuels will 

eventually be consumed as motor 

vehicle fuel, primarily through blending 

with gasoline or diesel. See further 

discussion in Section III.D. As a result, 

we do not believe that it is necessary to 

verify that blending has actually 

occurred in order to provide a program 

that adequately ensures it occurs. The 

American Petroleum Institute agreed 

that tracking renewable fuels to the 

point of blending would represent an 

unnecessary burden and added that 

such a requirement could preclude 

many obligated parties from taking 

direct steps to obtain RINs to meet their 

obligations. 

The Renewable Fuels Association, 

however, argued that allowing obligated 

parties to separate RINs from batches 

before blending occurred could give rise 

to RIN hoarding, fraud, and confusion. 

Most importantly, they noted, the 

alternative approach would provide 

direct verification of blending. For the 

reasons described in Section III.D, we 

do not believe that a compliance system 

requiring verification of blending is 

necessary, given that, with the 

exception of exports, essentially all 

renewable fuel produced in the U.S. is 

used as motor vehicle fuel in the U.S. 

This is a foundational principle of the 

use of a RIN-based program design that 

enjoyed widespread support among 

stakeholders and widespread 

recognition that it accurately describes 

real world practices. 

If verification of blending were 

required before a RIN could be 

separated from a batch, both obligated 

parties and blenders would be subject to 

additional recordkeeping and 

paperwork burdens. The Agency would 

be compelled to enforce activities at the 

blender level, adding about 1200 parties 

to the list of those subject to 

enforcement under our final program. 

Although we agree that the reformulated 

gasoline program could act as a model 

from which to construct such a 

recordkeeping and enforcement system, 

we continue to believe that such a 

system would be both unnecessary and 

burdensome. 

The Renewable Fuels Association also 

argued that our proposed program 

would result in confusion in the 

distribution system, since there would 

be renewable fuel both with and 

without RINs. However, there are many 

other reasons that this situation could 

arise, and none is expected to negatively 

impact the distribution of renewable 

fuels or the business agreements 

developed by parties transferring 

renewable fuels. For instance, we are 

exempting small volume producers from 

generating RINs, renewable fuels with 

equivalence values less than 1.0 may 

have fewer RINs than gallons, and 

volume swell and metering 

discrepancies can all contribute to 

situations in which batches legitimately 

do not have assigned RINs 

corresponding to their actual volumes. 

Parties that sell such batches could 

choose to price such product differently 

from product that has assigned RINs 

with a one-to-one correspondence to 

product volume. We are also requiring 

that PTDs associated with transfers of 

volume include notation indicating 

whether RINs are being simultaneously 

transferred to address these types of 

situations. 

Another commenter argued that the 

alternative approach could limit the 

potential for one refiner to purchase 

large volumes of renewable fuel with 

the intent of separating the RINs and 

exercising market power in the RIN 

market. However, the commenter did 

not provide any information regarding 

how such market power could be 

exercised by one refiner in a system 

where unassigned RINs can be 

transferred freely between parties any 

number of times, and access to those 

RINs is not limited geographically in 

any way. In addition, RINs that have 

been separated from their assigned 

batches by oxygenate blenders represent 

an additional safety valve in the RIN 

market, providing additional assurances 

that no one refiner could exercise 

market power in the RIN market. 

Commenters supporting a 

requirement that RINs be separated only 

at the point of blending offered no other 

arguments that hoarding or fraud could 

actually occur under our proposed 

approach. Therefore, we are finalizing 

an approach that requires obligated 

parties to separate RINs from batches at 

the point of ownership. 

IV. Registration, Recordkeeping, and 

Reporting Requirements 

A. Introduction 

Registration, recordkeeping and 

reporting are necessary to track 

compliance with the renewable fuels 

standard and transactions involving 

RINs. This summarizes these 

requirements. Our estimates as to the 

burden associated with registration, 

recordkeeping and reporting are 

contained in this Federal Register 

notice in Section XII.B and explained 

fully in ‘‘OMB–83 Supporting 

Statement—Renewable Fuels Standard 


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41 In this final rule, we have clearly distinguished 

expired RINs, which are no longer valid due to the 

passage of time, from retired RINs, which are RINs 

no longer valid due to the reportable spillage of 

their assigned volumes under § 80.1132, RINs used 

to satisfy an enforcement action, or RINs used to 

effect an import volume correction under 

§ 80.1166(k). Rather than leaving retired RINs under 

‘‘any additional information that the Administrator 

may require,’’ we have specifically addressed them 

in this final rule. We believe it is useful to 

specifically distinguish between retired and expired 

RINs because it will be easier for us to determine 

whether a report is complete and to quality assure 

and check reported information by applying a 

consistent reporting distinction between expired 

and retired RINs. 

(RFS) Program (Final Rule)—EPA ICR 

No. 2242.02,’’ which has been placed in 

the public docket for this rulemaking. 

B. Registration 

1. Who Must Register Under the RFS 

Program? 

Obligated parties (including refiners 

and importers), exporters of renewable 

fuels, producers and importers of 

renewable fuels, and any party who 

owns RINs must register with EPA. Any 

party may own RINs including, but not 

limited to, the above-named parties and 

marketers, blenders, terminal operators, 

jobbers, and brokers. Owning RINs, and 

engaging in any activities regarding 

RINs, is prohibited as of September 1, 

2007 unless the party has registered and 

received EPA company and facility 

identification numbers. 

Most refiners and importers and many 

biodiesel producers are already 

registered with us under various 

regulations in 40 CFR part 80 related to 

reformulated (RFG) and conventional 

gasoline or diesel fuel. Parties who are 

already registered will not have to take 

any action to register under the RFS 

program, because their existing 

registration will be applied to the RFS 

program as well. 

2. How Do I Register? 

Registration is a simple process. We 

will use the same basic forms for RFS 

program registration that we use under 

the reformulated gasoline (RFG) and 

anti-dumping program. You may 

download our registration forms at 

http://www.epa.gov/otaq/regs/fuels/ 

rfgforms.htm. These forms are well 

known in the regulated community and 

are very simple to fill out. Information 

requested includes company and facility 

names, addresses, and the identification 

of a contact person with telephone 

number and e-mail address. 

Registrations never expire and do not 

have to be renewed. However, all 

registered parties are responsible for 

notifying us of any change to their 

company or facility information. 

3. How Do I Know I Am Properly 

Registered With EPA? 

Upon receipt of a completed 

registration form, we will provide you 

with a unique 4-digit company 

identification number and a unique 

5-digit facility identification number. 

These numbers will appear in 

compliance reports and, in the case of 

renewable fuel producers and importers, 

they will be incorporated in the unique 

RINs they generate for each batch of 

renewable fuel. Timely registration is 

important because you cannot generate 

or handle transactions involving RINs 

until you have registered and received 

your registration numbers from us. It is 

advisable to register as soon as possible 

if you believe you will be engaged in 

activities that may require registration 

under the RFS program. Registration can 

occur any time following signature of 

this final rule. 

If you are already registered under 

another fuels program, such as RFG and 

anti-dumping or diesel sulfur, then you 

do not have to register again. You will 

use the same company and facility 

identification number you are currently 

using for RFS reporting. Parties in this 

situation may contact the Agency for 

confirmation or clarification of the 

appropriate registration numbers to use. 

As noted above, registrations never 

expire, but you are responsible for 

keeping the information we have up to 

date. If you have previously registered 

with us but have not had to report until 

now, then you may wish to contact the 

person listed on our renewable fuels 

Web page (http://www.epa.gov/otaq/ 

renewablefuels/index.htm) in order to 

confirm the information in your 

registration file. 

4. How Are Small Volume Domestic 

Producers of Renewable Fuels Treated 

for Registration Purposes? 

Small volume domestic producers of 

renewable fuels are those who produce 

less than 10,000 gallons per year or who 

import less than 10,000 gallons per year. 

These parties are not required to register 

if they do not wish to generate RINs. If 

a small volume domestic producer of 

renewable fuels wishes to generate 

RINs, then that party must register and 

comply with all recordkeeping and 

reporting requirements. 

C. Reporting 

1. Who Must Report Under the RFS 

Program? 

Obligated parties, exporters of 

renewable fuel, producers and importers 

of renewable fuel, and any party who 

owns either assigned or unassigned 

RINs such as marketers or brokers must 

submit periodic reports to us covering 

RIN generation, RIN use, and RIN 

transactions. 

2. What Reports Are Required Under the 

RFS Program? 

There are four basic reports under the 

RFS program. The first report is an 

annual compliance demonstration 

report that is required to be submitted 

by obligated parties and exporters of 

renewable fuel. This report provides the 

RFS compliance demonstration and is 

required to be submitted on an annual 

basis. It is focused on calculating the 

RVO, indicating RINs used for 

compliance, and determining any deficit 

carried over. 

The second report is a quarterly RIN 

generation report that is required to be 

submitted by producers and importers 

of renewable fuel. This report is focused 

on providing information on all batches 

of renewable fuel produced and 

imported and all RINs generated. 

The third report is a RIN transaction 

report that is required to be submitted 

by any party that owns RINs, including 

RIN marketers and brokers, as well as 

obligated parties, exporters, and 

renewable fuel producers and importers. 

This report is focused on providing 

information on individual RIN 

purchases, RIN sales, retired RINs, and 

expired RINs.41 A separate RIN 

transaction report is required to be 

submitted for each RIN purchase and 

sale, and for each retired or expired RIN, 

and must be submitted by the end of the 

quarter in which the activity occurred. 

The purpose of the RIN transaction 

report is to document the ownership 

and transfer of RINs, and to track 

expired and retired RINs. This report is 

necessary because compliance with the 

RVO is primarily demonstrated through 

self-reporting of RIN trades and 

therefore we must be able to link 

transactions involving each unique RIN 

in order to verify compliance. We will 

be able to import reports into our 

compliance database and match RINs to 

transactions across their entire journey 

from generation to use. As with our 

other 40 CFR part 80 compliance-onaverage and credit trading programs, 

many potential violations are expected 

to be self-reported. 

The fourth report is a quarterly gallonRIN activity report that also is required 

to be submitted by any party that owns 

RINs. This report is focused on the total 

number of gallon-RINs owned at the 

start and end of the quarter, and the 

total number of gallon-RINs purchased, 

sold, retired and expired during the 

quarter. This report also requires 


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information on end-of-quarter 

renewable fuel volumes. 

3. What Are the Specific Reporting 

Items for the Various Types of Parties 

Required To Report? 

The following table summarizes the 

information to be submitted in each 

type of report by the type of regulated 

party: 

TABLE IV.C.3–1.—INFORMATION CONTAINED IN REPORTS BY REGULATED PARTY * 

Type of report Obligated parties Exporters of renewable 

fuel 

Producers and importers 

of renewable fuel 

Other parties who own 

RINS 

Annual Compliance Demonstration Report.• Calculation of RVO .......

• List of RINs used for 

compliance.

• Calculation of deficit carryover.

• Calculation of RVO .......

• List of RINS used for 

compliance.

• Calculation of deficit carryover.

No report ........................... No report. 

Quarterly RIN Generation 

Report.

No report ........................... No report ........................... • Volume of each batch 

produced or imported.

• RINs generated for each 

batch.

• Volume of denaturant 

and applicable equivalence value of each 

batch.

No report. 

RIN Transaction Report .... Separate report for each 

transaction:.

• RIN purchase ................

• RIN sale ........................

• Expired RIN ...................

• Retired RIN ...................

Separate report for each 

transaction:.

• RIN purchase ................

• RIN sale ........................

• Expired RIN ...................

• Retired RIN ...................

Separate report for each 

transaction:.

• RIN purchase ................

• RIN sale ........................

• Expired RIN ...................

• Retired RIN ...................

Separate report for each 

transaction: 

• RIN purchase. 

• RIN sale. 

• Expired RIN. 

• Retired RIN. 

Quarterly gallon-RIN Activity Report.• Number of gallon-RINs* 

owned at start of quarter.

• Number of gallon-RINs 

purchased.

• Number of gallon-RINs 

sold.

• Number of gallon-RINs 

retired.

• Number of gallon-RINs 

expired (4th quarter 

only).

• Number of gallon-RINs 

at end of quarter.

• Volume (gals) of renewable fuel owned at end 

of quarter.

• Number of gallon-RINs 

owned at start of quarter.

• Number of gallon-RINs 

purchased.

• Number of gallon-RINs 

sold.

• Number of gallon-RINs 

retired.

• Number of gallon-RINS 

expired (4th quarter 

only).

• Number of gallon-RINs 

at end of quarter.

• Volume (gals) of renewable fuel owned at end 

of quarter.

• Number of gallon-RINs 

owned at start of quarter.

• Number of gallon-RINs 

purchased.

• Number of gallon-RINs 

sold.

• Number of gallon-RINs 

retired.

• Number of gallon-RINs 

expired (4th quarter 

only).

• Number of gallon-RINs 

at end of quarter.

• Volume (gals) of renewable fuel owned at end 

of quarter.

• Number of gallon-RINs 

owned at start of quarter. 

• Number of gallon-RINs 

purchased. 

• Number of gallon-RINs 

sold. 

• Number of gallon-RINs 

retired. 

• Number of gallon-RINs 

expired (4th quarter 

only). 

• Number of gallon-RINs 

at end of quarter. 

• Volume (gals) of renewable fuel owned at end 

of quarter. 

* A gallon-RIN is a RIN that represents an individual gallon of renewable fuel. See § 80.1101. 

4. What Are the Reporting Deadlines? 

In the proposed rule, we had 

requested comment on whether 

reporting should be annual or quarterly. 

After consideration of comments 

received, we have determined that each 

RIN transaction report must be 

submitted by the end of the quarter in 

which the transaction occurred, and the 

gallon-RIN activity report should be 

submitted quarterly. Quarterly reporting 

is better because it provides us with the 

information necessary to confirm the 

validity and legitimacy of RINs prior to 

their use in compliance. Additionally, 

quarterly reporting enables EPA to 

enforce the RIN/inventory balance 

requirements for producers and 

marketers of renewable fuels. 

The annual compliance 

demonstration for obligated parties must 

be submitted by February 28th for the 

prior calendar year. For the RIN 

transaction and quarterly gallon-RIN 

activity reports, the following schedule 

applies to all reporting parties: 

TABLE IV.C.4–1.—QUARTERLY REPORTING SCHEDULE FOR RFS PROGRAM

Quarter covered by 

quarterly report 

Due date for 

quarterly report 

January–March ................ May 31. 

April–June ........................ August 31. 

July–September ............... November 30. 

October–December ......... February 28. 

In the first year of the RFS program 

only, obligated parties and exporters are 

given an extra quarter to submit their 

list of RINs used to demonstrate 

compliance. This information must be 

reported by May 31, 2008 for calendar 

year 2007. All other reporting follows 

the schedule indicated above. 

5. How May I Submit Reports to EPA? 

We will use a simplified and secure 

method of reporting via the Agency’s 

Central Data Exchange (CDX). CDX 

permits us to accept reports that are 

electronically signed and certified by 

the submitter in a secure and robustly 

encrypted fashion. Using CDX will 

eliminate the need for wet ink 

signatures and will reduce the reporting 

burden on regulated parties. Guidance 

for reporting will be issued before 

implementation and will contain 

specific instructions and formats 

consistent with provisions in this final 

rule. The guidance will be posted on our 

renewable fuels Web page: http:// 


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www.epa.gov/otaq/renewablefuels/ 

index.htm. 

We will accept electronic reports 

generated in virtually all commercially 

available spreadsheet programs and will 

even permit parties to submit reports in 

comma delimited text, which can be 

generated with a variety of basic 

software packages. 

CDX will confirm delivery of your 

report. As described below with regard 

to recordkeeping, you must retain 

copies of all items submitted to us for 

five (5) years. 

6. What Does EPA Do With the Reports 

it Receives? 

In order to permit maximum 

flexibility in meeting the RFS program 

requirements, we must track activities 

involving the creation and use of RINs, 

as well as any transactions such as 

purchase or sale of RINs. Reports will be 

imported into a compliance database 

managed by EPA’s Office of 

Transportation and Air Quality and will 

be reviewed for completeness and for 

potential violations. It is important to 

keep your company contact updated 

(this is an item on the registration form), 

because we may need to speak to that 

person about any problems with a report 

submitted. Potential violations will be 

referred to EPA enforcement personnel. 

7. May I Claim Information in Reports 

as CBI and How Will EPA Protect it? 

You may claim information submitted 

to us as confidential business 

information (CBI). Please be sure to 

follow all reporting guidance and 

clearly mark the information you claim 

as proprietary. We will treat information 

covered by such a claim in accordance 

with the regulations at 40 CFR part 2 

and other Agency procedures for 

handling proprietary information. 

8. How Are Spilled Volumes With 

Associated Lost RINs To Be Handled in 

Reports? 

Since spills can happen whenever 

renewable fuel with assigned RINs is 

held, owners have two options if the 

spill causes their organization to be out 

of compliance. The owners of the 

spilled fuel may either retire RINs lost 

in reported spills or purchase and sell 

a volume of renewable fuel equal to the 

reported volume and not associated 

with RINs in order to meet compliance. 

Reportable spills for the purposes of this 

rule refers to spills of renewable fuel 

with assigned RINs and a requirement 

by a federal, state, or local authority to 

report said spills. The party that owns 

the spilled renewable fuel must retire a 

number of gallon-RINs corresponding to 

the volume of spilled renewable fuel 

multiplied by its equivalence value. If 

the equivalence value for the spilled 

volume may be determined based on its 

composition, then the appropriate 

equivalence value shall be used. If the 

equivalence value for the spilled 

volume cannot be determined, the 

equivalence value is 1.0. In the case that 

the fuel must be reported in pounds 

rather than gallons, the party that 

reported the spill should use the best 

available conversion for converting the 

volume into gallons. In the event that 

volume is spilled in transport, the 

owner of the RINs will need to request 

a copy of the spill report from the party 

that reported the spill. 

D. Recordkeeping 

1. What Types of Records Must Be Kept? 

The recordkeeping requirements for 

obligated parties and exporters of 

renewable fuels support the 

enforcement of the use of RINs for 

compliance purposes. Records kept by 

parties are central to tracking individual 

RINs through the fungible distribution 

system after those RINs are assigned to 

batches of renewable fuel. Parties use 

invoices or other types of product 

transfer documentation, which are 

customarily generated and issued in the 

course of business and which are 

familiar to parties who transfer or 

receive fuel. Parties are afforded 

significant freedom with regard to the 

form these documents take, although 

they must travel in some manner (on 

paper or electronically) with the volume 

of renewable fuel being transferred. On 

each occasion any person transfers 

ownership of renewable fuels subject to 

this regulation, that transferor must 

provide the transferee with documents 

identifying the renewable fuel and 

containing the identifying information 

that includes: The name and address of 

the transferor and transferee, the EPAissued company identification number 

of the transferor and transferee, the 

volume of renewable fuel that is being 

transferred, the date of transfer, and 

each associated RIN. These types of 

documents must be used by all parties 

in the distribution chain down to the 

point where the renewable fuel is 

blended into conventional gasoline or 

diesel. 

Except for transfers to truck carriers, 

retailers or wholesale purchaserconsumers, product codes may be used 

to convey the information required, as 

long as the codes are clearly understood 

by each transferee. However, the RIN 

must always appear in its entirety before 

it is separated from a batch, since it is 

a unique identification number that 

cannot be summarized by a shorter 

code. 

Parties must keep copies of all records 

for a period of not less than five (5) 

years. In addition to documentation 

related to transfers, parties must keep 

information related to the sale, 

purchase, brokering and trading of RINs 

and copies of any reports they submit to 

us for compliance reports. For example, 

if a volume of fuel and its associated 

RINs are reported to us as lost due to 

spillage, documentation related to that 

spill must be retained for the five year 

period. Upon request, parties are 

responsible for providing records to the 

Administrator or the Administrator’s 

authorized representative. 

2. What Recordkeeping Requirements 

Are Specific to Producers of Cellulosic 

or Waste-Derived Ethanol? 

In addition to the records applicable 

to all ethanol producers, producers of 

cellulosic biomass or waste-derived 

ethanol must keep records of fuel use in 

order to ensure compliance with, and 

enforcement of, the definitions of these 

types of renewable fuel. Producers of 

cellulosic biomass or waste-derived 

ethanol must keep records of volume 

and types of all feedstocks purchased to 

ensure compliance with, and 

enforcement of, the feedstock aspect of 

the definitions of cellulosic biomass and 

waste-derived ethanol. In addition, 

producers of cellulosic biomass or 

waste-derived ethanol are required to 

arrange for an independent third party 

to review the ethanol producer’s records 

and verify that the facility is, in fact, a 

cellulosic biomass or waste-derived 

ethanol production facility and that the 

ethanol producer is producing cellulosic 

biomass or waste-derived ethanol. The 

independent third party must be a 

licensed Professional Engineer (P.E.) in 

the chemical engineering field. 

Domestic ethanol producers are not 

required obtain prior approval of the 

independent third party P.E. or submit 

the engineering verification to EPA, 

however, the ethanol producer and the 

P.E. are required to keep records related 

to the required engineering verification 

and to produce them upon request of 

the Administrator or the Administrator’s 

authorized representative. 

A foreign ethanol producer may apply 

to us to have its cellulosic biomass or 

waste-derived ethanol treated in the 

same manner as domestic cellulosic 

biomass or waste-derived ethanol under 

the RFS program. A foreign ethanol 

producer with an approved application 

will be required to comply with all of 

the requirements that apply to domestic 

ethanol producers, including 

registration, recordkeeping, reporting, 


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attest engagements, and the 

independent third party verification 

discussed above. The attest engagements 

for a foreign ethanol producer must be 

conducted by a U.S. auditor (if not a 

U.S. based auditor, the auditor must be 

approved in advance by EPA). Similar 

to other fuels programs, the foreign 

ethanol producer will be required to 

comply with additional requirements 

designed to ensure that enforcement of 

the regulations at the foreign ethanol 

facility will not be compromised. The 

independent third party P.E. conducting 

the facility verification must be 

approved by EPA before the foreign 

entity will be allowed to treat its 

cellulosic biomass or waste-derived 

ethanol in the same manner as domestic 

producers. The foreign ethanol producer 

must arrange for the P.E. to inspect the 

facility and submit a report to us which 

describes the physical plant and its 

operation and includes documentation 

of the P.E.’s qualifications. The foreign 

ethanol producer must agree to provide 

access to EPA personnel for the 

purposes of conducting inspections and 

audits, post a bond, and arrange for an 

independent inspector to monitor ship 

loading and offloading records to ensure 

that volumes of ethanol do not change 

from port of shipping to port of entry. 

The independent inspector must be 

approved by EPA prior to the shipment 

of any ethanol designated by the foreign 

ethanol producer as ethanol which is to 

be treated as cellulosic biomass or 

waste-derived ethanol. Cellulosic 

biomass or waste-derived ethanol 

produced by a foreign ethanol producer 

must be identified as such on product 

transfer documents that accompany the 

ethanol to the importer. (These 

additional provisions for foreign ethanol 

producers are contained in § 80.1166.) 

The provisions for foreign ethanol 

producers are optional and are available 

only to foreign producers of cellulosic 

biomass or waste-derived ethanol. 

Ethanol or other renewable fuels 

produced and exported to the United 

States by other foreign producers are 

regulated through the importer. An 

importer that receives ethanol identified 

as cellulosic biomass or waste-derived 

ethanol produced by a foreign producer 

with an approved application would not 

assign RINs to the ethanol, as RINs for 

such ethanol will be assigned by the 

foreign ethanol producer. The importer, 

like any other marketer, would transfer 

the RINs assigned by the foreign 

producer with a volume of ethanol and 

report the transactions to us. 

E. Attest Engagements 

1. What Are the Attest Engagement 

Requirements Under the RFS Program? 

Attest engagements are similar to 

financial audits and consist of an 

independent, professional review of 

compliance records and reports. Similar 

to other fuels programs, the RFS 

program requires reporting parties to 

arrange for annual attest engagements to 

be conducted by an auditor that is 

‘‘independent’’ under the criteria 

specified in the regulations. We believe 

that the attest engagements provide an 

appropriate and useful tool for verifying 

the accuracy of the information reported 

to us. Attest engagements are performed 

in accordance with standard procedures 

and standards established by the 

American Institute of Certified Public 

Accountants and the Institute of Internal 

Auditors. The attest engagement 

consists of an outside certified public 

accountant (CPA) or certified 

independent auditor (CIA) following 

agreed upon procedures to determine 

whether underlying records, reported 

items, and transactions agree, and 

issuing a report as to their findings. 

Attest engagements are performed on an 

annual basis. 

2. Who Is Subject to the Attest 

Engagement Requirements for the RFS 

Program? 

Obligated parties, producers, 

exporters and importers of renewable 

fuel, and any party who own RINs are 

all subject to the attest engagement 

requirements. 

3. How Are the Attest Engagement 

Requirements in This Final Rule 

Different From Those Proposed? 

We had proposed that obligated 

parties, exporters, and renewable fuels 

producers be subject to attest 

engagement requirements. We received 

several comments on this proposal. 

Some commenters suggested that the 

attest engagements should be required 

for renewable fuels producers and 

importers, but not for obligated parties. 

These commenters believe that attest 

engagements are needed for renewable 

fuel producers and importers in order to 

verify reported production and RIN 

volumes, whereas we can monitor 

compliance by obligated parties by 

cross-checking their reports regarding 

RIN transactions and use with the 

reports from other parties. These 

commenters also believe that the 

information required by obligated 

parties under the RFS program is not 

such that an attest engagement is 

needed because the rule does not 

require verification of raw data as with 

other fuels programs. We have 

considered these comments but 

continue to believe that the attest 

engagements are an appropriate means 

of verifying the accuracy of the 

information reported to us by obligated 

parties. In addition to documentation of 

RIN transactions and use, the reports 

include information on production and 

import volumes and calculation of the 

party’s RFS obligation. We believe that 

attest engagements are necessary in 

order to verify that the underlying data 

regarding production and import 

volumes and RFS obligation, as well as 

the underlying data regarding RIN 

transactions and use, support the 

information included in the reports. As 

a result, the final rule includes an attest 

engagement requirement for obligated 

parties. 

We also received several comments 

that the attest engagement auditor 

should be required to examine only 

representative samples of the party’s 

RIN transaction documents rather than 

the documents for each RIN transaction, 

as required in the proposed regulations. 

We agree that examination of 

representative samples of RIN 

transaction documents would provide 

sufficient oversight and that the 

requirement included in the proposed 

regulations may be unnecessarily 

burdensome. As a result, the attest 

engagement provisions have been 

modified to require the auditor to 

examine only representative samples of 

RIN transaction documents. However, in 

the case of attest engagements applied to 

RIN generation by producers or 

importers of renewable fuel, or the use 

of RINs for compliance purposes by 

obligated parties or exporters, the 

auditor must examine documentation 

for all RINs generated or used. We 

believe this requirement is necessary to 

ensure that obligated parties and 

exporters are meeting their RFS 

obligation and that ethanol producers 

and importers are assigning RINs to 

each batch of renewable fuel produced 

or imported as required under the 

regulations. 

The proposed attest engagement 

regulations at § 80.1164(b) did not 

include importers of renewable fuels. 

One commenter pointed out these 

procedures should apply to both 

renewable fuels producers and 

importers. Renewable fuel importers 

have the same reporting requirements as 

renewable fuel producers, and, 

therefore, there is the same need for 

verification of the information given on 

the reports through attest engagements. 

It was an inadvertent oversight that 

renewable fuel importers were not 

included in the parties required to 


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23950 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

42Section 1501(b) of the Energy Policy Act of 

2005. 

comply with the attest engagement 

procedures in proposed § 80.1164(b), 

and that applying the requirements in 

§ 80.1164(b) to renewable fuel importers 

is a logical outgrowth of the proposed 

regulations. As a result, the regulations 

have been modified to include 

renewable fuel importers in the parties 

required to comply with the attest 

procedures in § 80.1164(b). 

In addition to obligated parties, 

exporters and renewable fuel producers 

and importers, we believe that an attest 

engagement requirement is necessary for 

any party who takes ownership of a RIN. 

As discussed above, attest engagements 

provide an appropriate and useful tool 

for verifying the accuracy of the 

information reported to us. Like 

obligated parties and renewable fuel 

producers and importers, the final rule 

requires RIN owners to submit 

information regarding RIN transaction 

activity to us. We believe that attest 

engagement audits are necessary to 

verify the accuracy of the information 

included in these reports. Therefore, 

this final rule includes an attest 

engagement requirement for RIN owners 

who are not obligated parties or 

renewable fuel producers or importers. 

We believe that inclusion of the 

requirement in the final rule is a logical 

outgrowth of the proposed attest 

engagement requirements for other 

parties who are required to submit 

similar information regarding RIN 

transaction activity to us. 

V. What Acts Are Prohibited and Who 

Is Liable for Violations? 

The prohibition and liability 

provisions applicable to the RFS 

program are similar to those of other 

gasoline programs. The final rule 

identifies certain prohibited acts, such 

as a failure to acquire sufficient RINs to 

meet a party’s renewable fuel obligation 

(RVO), producing or importing a 

renewable fuel without properly 

assigning a RIN, creating, transferring or 

using invalid RINs, improperly 

transferring renewable fuel volumes 

without RINs, improperly separating 

RINs from renewable fuel, retaining 

more RINs during a quarter than the 

party’s inventory of renewable fuel, or 

transferring RINs that are not identified 

by proper RIN numbers. Any person 

subject to a prohibition will be held 

liable for violating that prohibition. 

Thus, for example, an obligated party 

will be liable if the party fails to acquire 

sufficient RINs to meet its RVO. A party 

who produces or imports renewable 

fuels will be liable for a failure to 

properly assign RINs to batches of 

renewable fuel produced or imported. A 

renewable fuels marketer will be liable 

for improperly transferring renewable 

fuel volumes without RINs or retaining 

more RINs during a quarter than the 

party’s inventory of renewable fuels. 

Any party may be liable for creating, 

transferring, or using an invalid RIN, or 

transferring a RIN that is not properly 

identified. 

In addition, any person who is subject 

to an affirmative requirement under the 

RFS program will be liable for a failure 

to comply with the requirement. For 

example, an obligated party will be 

liable for a failure to comply with the 

annual compliance reporting 

requirements. A renewable fuel 

producer or importer will be liable for 

a failure to comply with the applicable 

renewable fuel batch reporting 

requirements. Any party subject to 

recordkeeping or product transfer 

document requirements would be liable 

for a failure to comply with these 

requirements. Like other EPA fuels 

programs, the final rule provides that a 

party who causes another party to 

violate a prohibition or fail to comply 

with a requirement may be found liable 

for the violation. 

The Energy Act amended the penalty 

and injunction provisions in section 

211(d) of the Clean Air Act to apply to 

violations of the renewable fuels 

requirements in section 211(o).42

Accordingly, under the final rule, any 

person who violates any prohibition or 

requirement of the RFS program may be 

subject to civil penalties for every day 

of each such violation and the amount 

of economic benefit or savings resulting 

from the violation. Under the final rule, 

a failure to acquire sufficient RINs to 

meet a party’s renewable fuels 

obligation will constitute a separate day 

of violation for each day the violation 

occurred during the annual averaging 

period. 

Because there are no standards under 

the RFS rule that may be measured 

downstream, we believe that a 

presumptive liability scheme, i.e., a 

scheme in which parties upstream from 

the facility where the violation is found 

are presumed liable for the violation, 

would not be applicable under the RFS 

program. As a result, the RFS rule does 

not contain such a scheme. 

The regulations prohibit any party 

from creating, transferring or using 

invalid RINs. These invalid RIN 

provisions apply regardless of the good 

faith belief of a party that the RINs are 

valid. These enforcement provisions are 

necessary to ensure the RFS program 

goals are not compromised by illegal 

conduct in the creation and transfer of 

RINs. 

Any obligated party that reports the 

use of invalid RINs to meet its 

renewable fuels obligation may be liable 

for a regulatory violation for use of 

invalid RINs. If the obligated party fails 

to meet its renewable fuels obligation 

without the invalid RINs, the party may 

also be liable for not meeting its 

renewable fuels obligation. In addition, 

the transfer of invalid RINs is 

prohibited, so that any party or parties 

that transfer invalid RINs may be liable 

for a regulatory violation for transferring 

the invalid RINs. In a case where invalid 

RINs are transferred and used, EPA 

normally will hold each party that 

committed a violation responsible, 

including both the user and the 

transferor of the invalid RINs. For this 

reason, obligated parties and RIN 

brokers should use good business 

judgment when deciding whether to 

purchase RINs from any particular seller 

and should consider including prudent 

business safeguards in RIN transactions, 

such as requiring RIN sellers to sign 

contracts with indemnity provisions to 

protect the purchaser in the event 

penalties are assessed because we find 

the RINs are invalid. Similarly, parties 

that sell RINs should take steps to 

ensure any RINs that are sold were 

properly created to avoid penalties that 

result from the transfer of invalid RINs. 

As in other motor vehicle fuel credit 

programs, the regulations address the 

consequences if an obligated party is 

found to have used invalid RINs to 

demonstrate compliance with its RVO. 

In this situation, the obligated party that 

used the invalid RINs will be required 

to deduct any invalid RINs from its 

compliance calculations. As discussed 

above, the obligated party will be liable 

for not meeting its renewable fuels 

obligation if the remaining number of 

valid RINs is insufficient to meet its 

RVO, and the obligated party may be 

subject to monetary penalties if it used 

invalid RINs in its compliance 

demonstration. In determining an 

appropriate penalty, EPA will consider 

a number of factors, including whether 

the obligated party did in fact procure 

sufficient valid RINs to cover the deficit 

created by the invalid RINs. A penalty 

may include both the economic benefit 

of using invalid RINs and a gravity 

component. 

Although an obligated party may be 

liable for a violation if it uses invalid 

RINs for compliance purposes, we 

normally will look first to the generator 

or seller of the invalid RINs both for 

payment of penalty and to procure 

sufficient valid RINs to offset the invalid 

RINs. However, if EPA is unable to 


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Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 23951 

43The October 2006 ethanol production capacity 

baseline was generated based on the June 2006 

NPRM plant list and updated on October 18, 2006 

based on a variety of data sources including: 

Renewable Fuels Association (RFA), Ethanol 

Biorefinery Locations (updated October 16, 2006); 

Ethanol Producer Magazine (EPM), plant list 

(downloaded October 18, 2006) and monthly 

publications (June 2006 through October 2006); ICF 

International, Ethanol Industry Profile (September 

30, 2006); BioFuels Journal, News & Information for 

the Ethanol and BioFuels Industries (breaking news 

posted June 16, 2006 through October 18, 2006); 

and ethanol producer Web sites. The baseline 

includes small-scale ethanol production facilities as 

well as former food-grade ethanol plants that have 

since transitioned into the fuel-grade ethanol 

market. Where applicable, current ethanol plant 

production levels have been used to represent plant 

capacity, as nameplate capacities are often 

underestimated. This analysis does not consider 

ethanol plants that may be located in the Virgin 

Islands or U.S. territories. 

obtain relief from that party, attention 

will turn to the obligated party who may 

then be required to obtain sufficient 

valid RINs to offset the invalid RINs. 

We received several comments on the 

prohibition regarding use of invalid 

RINs. Some commenters believe that an 

obligated party that uses RINs which are 

later found to be invalid should be given 

an opportunity to ‘‘cure’’ the shortfall 

caused by the invalid RINs without 

penalty. As indicated above, a penalty 

for a good faith purchaser is not 

automatic. Where an invalid RIN was 

created by another party, such as the 

producer or marketer of the renewable 

fuel, the party responsible for the 

existence of the invalid RIN would be 

liable and would be required to 

purchase a RIN to make up for the 

invalid RIN and pay an appropriate 

penalty. If the responsible party cannot 

be identified or is out of business, or if 

EPA is otherwise unable to obtain relief 

from the party, then the obligated party 

that used the RIN would be required to 

purchase a RIN to make up for the 

invalid RIN. However, any penalty for a 

good faith purchaser would likely be 

small, particularly where EPA is able to 

obtain relief from the party that was 

responsible for the invalid RIN. Where 

a RIN was originally believed to be valid 

but is later found to be invalid, whether 

a current year RIN may be used to make 

up for the prior-year invalid RIN would 

be determined in the context of the 

enforcement action. 

Another commenter suggested that an 

obligated party should not be liable for 

a violation unless the party knowingly 

used the invalid RINs to demonstrate 

compliance. Where the suspect RINs are 

later proved to be valid, the party 

should be able to use the RINs in the 

subsequent year regardless of the year of 

generation or any rollover cap. For the 

reasons stated above, we believe that it 

is appropriate to hold an obligated party 

responsible for using invalid RINs even 

where the party in good faith believed 

the RINs to be valid. Normally, suspect 

RINs will be not be replaced until the 

RINs are proved to be invalid. In the 

unlikely circumstance that a RIN is first 

determined to be invalid and then later 

found to be valid, the ability to use the 

RIN in a subsequent year would be 

determined in the context of the 

enforcement action. 

Finally, parties that are predominately 

renewable fuel producers or importers, 

but which must be designated as 

obligated parties due to the production 

or importation of a small amount of 

gasoline, should not be able to separate 

RINs from all renewable fuels that they 

own. To address such circumstances, 

we are prohibiting obligated parties 

from separating RINs that they generate 

from volumes of renewable fuel in 

excess of their RVO. However, obligated 

parties must separate any RINs 

generated by other parties from 

renewable fuel if they own the 

renewable fuel. 

VI. Current and Projected Renewable 

Fuel Production and Use 

While the definition of renewable fuel 

does not limit compliance with the 

standard to any one particular type of 

renewable fuel, ethanol is currently the 

most prevalent renewable fuel blended 

into gasoline today. Biodiesel represents 

another renewable fuel which, while not 

as widespread as ethanol use (in terms 

of volume), has been increasing in 

production capacity and use over the 

last several years. This section provides 

a brief overview of the ethanol and 

biodiesel industries today and how they 

are projected to grow into the future. 

A. Overview of U.S. Ethanol Industry 

and Future Production/Consumption 

1. Current Ethanol Production 

As of October 2006, there were 110 

ethanol production facilities operating 

in the United States with a combined 

production capacity of approximately 

5.2 billion gallons per year.43 All of the 

ethanol currently produced comes from 

grain or starch-based feedstocks that can 

easily be broken down into ethanol via 

traditional fermentation processes. The 

majority of ethanol (almost 92 percent 

by volume) is produced exclusively 

from corn. Another 7 percent comes 

from a blend of corn and/or similarly 

processed grains (milo, wheat, or barley) 

and less than 1 percent is produced 

from waste beverages, cheese whey, and 

sugars/starches combined. A summary 

of ethanol production by feedstock is 

presented in Table VI.A.1–1. 

TABLE VI.A.1–1.—2006 U.S. ETHANOL PRODUCTION BY FEEDSTOCK

Plant feedstock Capacity 

MMgy 

Percent 

of 

capacity 

Number 

of plants 

Percent 

of plants 

Cheese Whey .................................................................................................................................. 8 0.1 2 1.8 

Corn a ............................................................................................................................................... 4,780 91.6 90 81.8 

Corn, Barley ..................................................................................................................................... 40 0.8 1 0.9 

Corn, Milo b ...................................................................................................................................... 244 4.7 8 7.3 

Corn, Wheat ..................................................................................................................................... 90 1.7 2 1.8 

Milo, Wheat ...................................................................................................................................... 40 0.8 1 0.9 

Sugars, Starches ............................................................................................................................. 2 0.0 1 0.9 

Waste Beverages c ........................................................................................................................... 16 0.3 5 4.5 

Total .......................................................................................................................................... 5,218 100.0 110 100.0 

a Includes two facilities processing seed corn and another facility processing corn which intends to transition to corn stalks, switchgrass, and 

biomass in the future. b Includes one facility procesisng small amounts of molasses in addition to corn and milo. 

c Includes two facilities processing brewery waste. 


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23952 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

44Facilities were assumed to burn natural gas if 

the plant fuel type was not mentioned or 

unavailable. 

There are a total of 102 plants 

processing corn and/or other similarly 

processed grains. Of these facilities, 92 

utilize dry-milling technologies and the 

remaining 10 plants rely on wet-milling 

processes. Dry mill ethanol plants grind 

the entire kernel and produce only one 

primary co-product: Distillers’ grains 

with solubles (DGS). The co-product is 

sold wet (WDGS) or dried (DDGS) to the 

agricultural market as animal feed. In 

contrast to dry mill plants, wet mill 

facilities separate the kernel prior to 

processing and in turn produce other 

co-products (usually gluten feed, gluten 

meal, and oil) in addition to DGS. Wet 

mill plants are generally more costly to 

build but are larger in size on average. 

As such, nearly 22 percent of the 

current overall ethanol production 

comes from the 10 previouslymentioned wet mill facilities. 

The remaining 8 plants which process 

waste beverages, cheese whey, or 

sugars/starches, operate differently than 

their grain-based counterparts. These 

facilities do not require milling and 

instead operate a simpler enzymatic 

fermentation process. 

In addition to grain and starch-toethanol production, another method 

exists for producing ethanol from a 

more diverse feedstock base. This 

process involves converting cellulosic 

materials such as bagasse, wood, straw, 

switchgrass, and other biomass into 

ethanol. Cellulose consists of tightlylinked polymers of starch, and 

production of ethanol from it requires 

additional steps to convert these 

polymers into fermentable sugars. 

Scientists are actively pursuing acid and 

enzyme hydrolysis as well as 

gasification to achieve this goal, but the 

technologies are still not fully 

developed for large-scale commercial 

production. As of October 2006, the 

only known cellulose-to-ethanol plant 

in North America was Iogen in Canada, 

which produces approximately one 

million gallons of ethanol per year from 

wood chips. Several companies have 

announced plans to build cellulose-toethanol plants in the U.S., but most are 

still in the research and development or 

pre-construction planning phases. The 

majority of the plans involve converting 

bagasse, rice hulls, wood, switchgrass, 

corn stalks, and other agricultural waste 

or biomass into ethanol. For a more 

detailed discussion on future cellulosic 

ethanol plants and production 

technologies, refer to RIA Sections 

1.2.3.6 and 7.1.2, respectively. 

Ethanol production is a relatively 

resource-intensive process that requires 

the use of water, electricity, and steam. 

Steam needed to heat the process is 

generally produced onsite or by other 

dedicated boilers. Of today’s 110 

ethanol production facilities, 101 burn 

natural gas, 7 burn coal, 1 burns coal 

and biomass, and 1 burns syrup from 

the process to produce steam.44 Our 

research suggests that 11 plants 

currently utilize cogeneration or 

combined heat and power (CHP) 

technology, although others may exist. 

CHP is a mechanism for improving 

overall plant efficiency. Whether owned 

by the ethanol facility, their local utility, 

or a third party; CHP facilities produce 

their own electricity and use the waste 

heat from power production for process 

steam, reducing the energy intensity of 

ethanol production. A summary of the 

energy sources and CHP technology 

utilized by today’s ethanol plants is 

found in Table VI.A.1–2. 

TABLE VI.A.1–2.—2006 U.S. ETHANOL PRODUCTION BY ENERGY SOURCE

Plant energy source Capacity 

MMgy 

Percent 

of 

capacity 

Number 

of plants 

Percent 

of plants 

CHP 

tech. 

Coal .............................................................................................................................. 1,042 20.0 7 6.3 2 

Coal, Biomass .............................................................................................................. 50 1.0 1 0.9 0 

Natural Gas a ................................................................................................................ 4,077 78.1 101 91.8 9 

Syrup ............................................................................................................................ 48 0.9 1 0.9 0 

Total ...................................................................................................................... 5,218 100.0 110 100.0 11 

a Includes three facilities burning natural gas which intend to transition to coal or biomass in the future. 

The majority of domestic ethanol is 

currently produced in the Midwest 

within PADD 2—where most of the corn 

is grown. Of the 110 U.S. ethanol 

production facilities, 100 are located in 

PADD 2. As a region, PADD 2 accounts 

for 96 percent (or over five billion 

gallons) of the annual domestic ethanol 

production, as shown in Table VI.A.1– 

3. 

TABLE VI.A.1–3.—2006 U.S. ETHANOL PRODUCTION BY PADD 

PADD Capacity 

MMgy 

Percent 

of 

capacity 

Number 

of plants 

Percent 

of plants 

PADD 1 ............................................................................................................................................ 0.4 0.0 1 0.9 

PADD 2 ............................................................................................................................................ 5,012 96.0 100 90.9 

PADD 3 ............................................................................................................................................ 30 0.6 1 0.9 

PADD 4 ............................................................................................................................................ 105 2.0 4 3.6 

PADD 5 ............................................................................................................................................ 71 1.4 4 3.6 

Total .......................................................................................................................................... 5,218 100.0 110 100.0 


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Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 23953 

45 Includes Broin’s minority ownership in 18 U.S. 

ethanol plants. 

46Based on RFA comments received in response 

to the proposed rulemaking, 71 FR 55552 

(September 22, 2006). 

Leading the Midwest in ethanol 

production are Iowa, Illinois, Nebraska, 

Minnesota, and South Dakota with a 

combined capacity of nearly four billion 

gallons per year. Together, these five 

states’ 70 ethanol plants account for 76 

percent of the total domestic product. 

However, although the majority of 

ethanol production comes from PADD 2, 

there are a growing number of plants 

located outside the traditional corn belt. 

In addition to the 15 states comprising 

PADD 2, ethanol plants are currently 

located in California, Colorado, Georgia, 

New Mexico, and Wyoming. Some of 

these facilities ship in feedstocks 

(namely corn) from the Midwest, others 

rely on locally grown/produced 

feedstocks, while others rely on a 

combination of both. 

The U.S. ethanol industry is currently 

comprised of a mixture of corporations 

and farmer-owned cooperatives (coops). More than half (or 60) of today’s 

plants are owned by corporations and, 

on average, these plants are larger in 

size than farmer-owned co-ops. 

Accordingly, company-owned plants 

account for almost 64 percent of the 

total U.S. ethanol production capacity. 

Further, more than 50 percent of the 

total domestic product comes from 

plants owned by just 6 different 

companies—Archer Daniels Midland, 

Broin, VeraSun, Hawkeye Renewables, 

Global/MGP Ingredients, and Aventine 

Renewable Energy.45

2. Expected Growth in Ethanol 

Production 

Over the past 25 years, domestic fuel 

ethanol production has steadily 

increased due to environmental 

regulation, federal and state tax 

incentives, and market demand. More 

recently, ethanol production has soared 

due to the phase out of MTBE, an 

increasing number of state ethanol 

mandates, and elevated crude oil prices. 

As shown in Figure VI.A.2–1, over the 

past three years, domestic ethanol 

production has nearly doubled from 2.1 

billion gallons in 2002 to 4.0 billion 

gallons in 2005. For 2006, the 

Renewable Fuels Association is 

anticipating about 4.7 billion gallons of 

domestic ethanol production.46

EPA forecasts that domestic ethanol 

production will continue to grow into 

the future. In addition to the past 

impacts of federal and state tax 

incentives, as well as the more recent 

impacts of state ethanol mandates and 

the removal of MTBE from all U.S. 

gasoline, crude oil prices are expected 

to continue to drive up demand for 


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23954 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

47Under construction plant locatons, capacities, 

feedstocks, and energy sources as well as planned/ 

proposed plant locations and capacities were 

derived from a variety of data soruces including 

Renewable Fuels Association (RFA), Ethanol 

Biorefinery Locations (updated October 16, 2006); 

Ethanol Producer Magazine (EPM), under 

construction plant list (downloaded October 18, 

2006) and monthly publications (June 2006 through 

October 2006); ICF International, Ethanol Industry 

Profile (September 30, 2006); BioFuels Journal, 

News & Information for the Ethanol and BioFuels 

Industries (breaking news posted June 16, 2006 

through October 18, 2006); and ethanol producer 

Web sites. This analysis does not consider ethanol 

plants under construction or planned for the Virgin 

Islands or U.S. territories. 

48Construction timelines based on information 

obtained from press releases and ethanol producer 

Web sites. 

ethanol. As a result, the nation is on 

track to exceed the renewable fuel 

volume requirements contained in the 

Act. Today’s ethanol production 

capacity (5.2 billion gallons) is already 

exceeding the 2007 renewable fuel 

requirement (4.7 billion gallons). In 

addition, there is another 3.4 billion 

gallons of ethanol production capacity 

currently under construction.47 A 

summary of the new construction and 

plant expansion projects currently 

underway (as of October 2006) is found 

in Table VI.A.2–1. 

TABLE VI.A.2–1.—UNDER CONSTRUCTION U.S. ETHANOL PRODUCTION CAPACITY

PADD 

Oct. 2006 baseline Under const. Base + under const. 

MMgy Plants MMgy a Plants MMgy a Plants 

PADD 1 .......................................................................... 0 .4 1 115 1 115 2 

PADD 2 .......................................................................... 5,012 100 2,764 39 7,776 139 

PADD 3 .......................................................................... 30 1 230 3 260 4 

PADD 4 .......................................................................... 105 4 50 1 155 5 

PADD 5 .......................................................................... 71 4 198 3 269 7 

Total ........................................................................ 5,218 110 3,357 47 8,575 157 

a Includes plant expansions. 

A select group of builders, technology 

providers, and construction contractors 

are completing the majority of the 

construction projects described in Table 

VI.A.2–1. As such, the completion dates 

of these projects are staggered over 

approximately 18 months, resulting in 

the gradual phase-in of ethanol 

production shown in Figure VI.A.2–2.48


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Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 23955 

As shown in Table VI.A.2–1 and 

Figure VI.A.2–2, once all the 

construction projects currently 

underway are complete (estimated by 

March 2008), the resulting U.S. ethanol 

production capacity would be about 8.6 

billion gallons. Without even 

considering forecasted biodiesel 

production (described below in Section 

VI.B.1), this would be more than enough 

renewable fuel to satisfy the 2012 RFS 

requirements (7.5 billion gallons). 

However, ethanol production is 

expected to continue to grow. There are 

more and more ethanol projects being 

announced each day. These potential 

projects are at various stages of planning 

from conducting feasibility studies to 

gaining local approval to applying for 

permits to financing/fundraising to 

obtaining contractor agreements. 

Together these potential projects could 

result in an additional 21 billion gallons 

of ethanol production capacity as shown 

in Table VI.A.2–2. 

TABLE VI.A.2–2.—OTHER POTENTIAL U.S. ETHANOL PRODUCTION CAPACITY

PADD 

Base + under const. Planned Proposed 

MMgy a Plants MMgy a Plants MMgy a Plants 

PADD 1 .................................................................................................... 115 2 548.0 8 934 21 

PADD 2 .................................................................................................... 7,776 139 4,633 44 11,722 136 

PADD 3 .................................................................................................... 260 4 250 4 876 14 

PADD 4 .................................................................................................... 155 5 100 1 783 14 

PADD 5 .................................................................................................... 269 7 232 8 775 23 

Subtotal ...................................................................................... 8,575 157 5,763 65 15,090 208 

Total b ......................................................................................... ................ ................ 14,339 222 29,428 430 

a Includes plant expansions. 

bTotal including existing plus under construction plants. 

Although there is clearly a great 

potential for ethanol production growth, 

it is highly unlikely that all the 

announced projects would actually 

reach completion in a reasonable 

amount of time, or at all, considering 

the large number of projects moving 

forward. Since there is no precise way 

to know exactly which plants will come 


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23956 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

49A more detailed summary of the plants we 

considered is found in a March 5, 2007 note to the 

docket titled: RFS Industry Characterization— 

Ethanol Production. 

to fruition in the future, we have chosen 

to focus our subsequent discussion on 

forecasted ethanol production on plants 

which are likely to be online by 2012.49

This includes existing plants as well as 

projects which are under construction 

(refer to Table VI.A.2–1) or in the final 

planning stages (denoted as ‘‘planned’’ 

in Table VI.A.2–2). The distinction 

between ‘‘planned’’ versus ‘‘proposed’’ 

is that as of October 2006 planned 

projects had completed permitting, 

fundraising/financing, and had builders 

assigned with definitive construction 

timelines whereas proposed projects did 

not. 

TABLE VI.A.2–3.—FORECASTED 2012 ETHANOL PRODUCTION BY PADD 

PADD Capacity 

MMgy 

Percent 

of 

capacity 

Number 

of plants 

Percent 

of plants 

PADD 1 ............................................................................................................................................ 663 4.6 10 4.5 

PADD 2 ............................................................................................................................................ 12,409 86.5 183 82.4 

PADD 3 ............................................................................................................................................ 510 3.6 8 3.6 

PADD 4 ............................................................................................................................................ 255 1.8 6 2.7 

PADD 5 ............................................................................................................................................ 501 3.5 15 6.8 

Total .......................................................................................................................................... 14,339 100.0 222 100.0 

As shown above in Table VI.A.2–3, 

once all the under construction and 

planned projects are complete the 

resulting ethanol production capacity 

would be 14.3 billion gallons. The 

majority of which would still originate 

from PADD 2. This volume, expected to 

be online by 2012, exceeds the EIA AEO 

2006 demand estimate (9.6 billion 

gallons by 2012, discussed more in RIA 

Section 2.1). The forecasted growth 

would nearly triple today’s production 

capacity and greatly exceed the 2012 

RFS requirement (7.5 billion gallons). 

While our forecast represents ethanol 

production capacity (actual production 

could be lower), we believe it is still a 

good indicator of what domestic ethanol 

production could look like in the future. 

In addition, we predict that domestic 

ethanol production will continue to be 

supplemented by imports in the future. 

According to a current report by F.O. 

Licht, U.S. net import demand is 

estimated to be around 300 million 

gallons per year by 2012, being supplied 

primarily through the Caribbean Basin 

Initiative (CBI), with some direct 

imports from Brazil during times of 

shortfall or high price. For more 

information on ethanol imports, refer to 

RIA Section 1.5. 

Of the 112 forecasted new ethanol 

plants (47 under construction and 65 

planned), 106 would rely on grain-based 

feedstocks. More specifically, 89 would 

rely exclusively on corn, 13 would 

process a blend of corn and/or similarly 

processed grains (milo or wheat), 3 

would process molasses, and 1 would 

process a combination of molasses and 

sweet sorghum (milo). Of the remaining 

six plants (all in the planned stage), four 

would process cellulosic biomass 

feedstocks and two would start off 

processing corn and later transition to 

cellulosic materials. Of the four 

dedicated cellulosic plants, one would 

process bagasse, one would process a 

combination of bagasse and wood, and 

two would process biomass. Of the two 

transitional corn/cellulosic plants, one 

would ultimately process a combination 

of bagasse, rice hulls, and wood and the 

other would ultimately process wood 

and other agricultural residues. In 

addition to the forecasted new plants, 

an existing corn ethanol plant plans to 

expand production and transition to 

corn stalks, switchgrass, and biomass in 

the future. A summary of the resulting 

overall feedstock usage (including 

current, under construction, and 

planned projects) is found in Table 

VI.A.2–4. 

TABLE VI.A.2–4.—FORECASTED 2012 U.S. ETHANOL PRODUCTION BY FEEDSTOCK

Plant feedstock Capacity 

MMgy 

Percent 

of 

capacity 

Number 

of plants 

Percent 

of plants 

Bagasse ........................................................................................................................................... 7 0.1 1 0.5 

Bagasse, Wood ............................................................................................................................... 2 0.0 1 0.5 

Bagasse, Wood, Rice Hulls a ........................................................................................................... 108 0.8 1 0.5 

Biomass ........................................................................................................................................... 55 0.4 2 0.9 

Cheese Whey .................................................................................................................................. 8 0.1 2 0.9 

Corn b ............................................................................................................................................... 12,495 87.1 178 80.2 

Corn, Barley ..................................................................................................................................... 40 0.3 1 0.5 

Corn, Milo c ...................................................................................................................................... 1,132 7.9 20 9.0 

Corn, Wheat ..................................................................................................................................... 235 1.6 3 1.4 

Corn Stalks, Switchgrass, Biomass a ............................................................................................... 40 0.3 1 0.5 

Milo, Wheat ...................................................................................................................................... 40 0.3 1 0.5 

Molasses d ........................................................................................................................................ 52 0.4 4 1.8 

Sugars, Starches ............................................................................................................................. 2 0.0 1 0.5 

Waste Beverages e .......................................................................................................................... 16 0.1 5 2.3 

Wood Agricultural Residues a .......................................................................................................... 108 0.8 1 0.5 

Total .......................................................................................................................................... 14,339 100.0 222 100.0 

aFacilities plan to start off processing corn. 


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50We anticipate a ramp-up in cellulosic ethanol 

production in the years to come so that capacity 

exists to satisfy the Act’s 2013 requirement (250 

million gallons of cellulosic biomass ethanol). 

Therefore, for subsequent analysis purposes, we 

have assumed that 250 million gallons of ethanol 

would come from cellulosic biomass sources by 

2012. 

51EIA Monthly Energy Review, June 2006 (Table 

10.1: Renewable Energy Consumption by Source, 

Appendix A: Thermal Conversion Factors). 

52File containing historical RFG MTBE usage 

obtained from EIA representative on March 9, 2006. 

53EIA 2004 Petroleum Marketing Annually (Table 

48: Prime Supplier Sales Volumes of Motor 

Continued 

b Includes two facilities processing seed corn. 

c Includes one facility processing small amounts of molasses in addition to corn and milo. 

d Includes one facility planning to process sweet sorghum (milo) in addition to molasses. 

e Includes two facilities processing brewery waste. 

Of the 112 forecasted new plants, 100 

would burn some amount of natural 

gas—at least initially. More specifically, 

91 plants would rely exclusively on 

natural gas; 2 would rely on a 

combination of natural gas, bran and 

biomass; 1 would burn a combination of 

natural gas, distillers’ grains and syrup; 

and 6 would start off burning natural 

gas and later transition to coal. As for 

the remaining 12 plants, 3 would burn 

manure-derived methane (biogas); 7 

would rely exclusively on coal; 1 would 

burn a combination of coal and biomass; 

and 1 would burn a combination of coal, 

tires and biomass. In addition to the 

new ethanol plants, three existing plants 

currently burning natural gas are 

predicted to transition to alternate boiler 

fuels in the future. More specifically, 

two plants plan to transition to biomass 

and one plans to start burning coal. Our 

research suggests that 7 of the new 

plants would utilize combined heat and 

power (CHP) technology, although 

others may exist. Three of the new CHP 

plants would burn natural gas, three 

would burn coal, and one would burn 

a combination of coal, tires, and 

biomass. Among the existing CHP 

plants, two are predicted to transition 

from natural gas to coal or biomass at 

this time. Overall, the net number of 

CHP ethanol plants would increase from 

11 to 18. A summary of the resulting 

overall plant energy source utilization is 

found below in Table VI.A.2–5. 

TABLE VI.A.2–5.—FORECASTED 2012 U.S. ETHANOL PRODUCTION BY ENERGY SOURCE

Plant energy source Capacity 

MMgy 

Percent 

of 

capacity 

Number 

of plants 

Percent 

of plants 

CHP 

tech. 

Biomass a ..................................................................................................................... 112 0.8 2 0.9 1 

Coal b ............................................................................................................................ 2,095 14.6 21 9.5 6 

Coal, Biomass .............................................................................................................. 75 0.5 2 0.9 0 

Coal, Biomass, Tires .................................................................................................... 275 1.9 1 0.5 1 

Manure Biogas c ........................................................................................................... 144 1.0 3 1.4 0 

Natural Gas .................................................................................................................. 11,275 78.6 189 85.1 10 

Natural Gas, Bran, Biomass ........................................................................................ 264 1.8 2 0.9 0 

Natural Gas, Distiller’s Grain, Syrup ............................................................................ 50 0.3 1 0.5 0

Syrup ............................................................................................................................ 49 0.3 1 0.5 0 

Total ...................................................................................................................... 14,339 100.0 222 100.0 18 

a Represents two existing natural gas-fired plants that plan to transition to biomass. 

b Includes two plants planning on burning lignite coal or coal lines. Includes one existing plant currently burning natural gas that plans to transition to coal. Includes six new plants that will start off burning natural gas and later transition to coal. c Includes one facility planning on burning cotton gin in addition to manure biogas. 

The Energy Policy Act of 2005 

requires that 250 million gallons of the 

renewable fuel consumed in 2013 and 

beyond meet the definition of cellulosic 

biomass ethanol. The Act defines 

cellulosic biomass ethanol as ethanol 

derived from any lignocellulosic or 

hemicellulosic matter that is available 

on a renewable or recurring basis 

including dedicated energy crops and 

trees, wood and wood residues, plants, 

grasses, agricultural residues, fibers, 

animal wastes and other waste 

materials, and municipal solid waste. 

The term also includes any ethanol 

produced in facilities where animal or 

other waste materials are digested or 

otherwise used to displace 90 percent of 

more of the fossil fuel normally used in 

the production of ethanol. 

As shown in Table VI.A.2–4, there are 

seven ethanol plants planning to utilize 

cellulosic feedstocks in the future. 

These facilities have a combined 

ethanol production capacity of 320 

million gallons per year. It is unclear 

whether these plants would be online 

and capable of producing 250 million 

gallons of ethanol by 2013 to meet the 

Act’s cellulosic biomass ethanol 

requirement. However, as shown in 

Table VI.A.2–5, there are 12 facilities 

that burn or plan to burn waste 

materials to power their ethanol plants. 

Depending on how much fossil fuel is 

displaced, these facilities (with a 

combined ethanol production capacity 

of 969 million gallons per year) could 

also meet the definition of cellulosic 

biomass ethanol under the Act. 

Considering both feedstock and waste 

energy plants, the total cellulosic 

ethanol potential could be as high as 1.3 

billion gallons. Even if only one fifth of 

this ethanol were to end up qualifying 

as cellulosic biomass ethanol or come to 

fruition by 2013, it would be more than 

enough to satisfy the 250 million gallon 

requirement specified in the Act.50

3. Current Ethanol and MTBE 

Consumption 

To understand the impact of the 

increased ethanol production/use on 

gasoline properties and in turn overall 

air quality, we first need to gain a better 

understanding of where ethanol is used 

today and how the picture is going to 

change in the future. As such, in 

addition to the production analysis 

presented above, we have completed a 

parallel consumption analysis 

comparing current ethanol consumption 

to future predictions. 

In the 2004 base case, 3.5 billion 

gallons of ethanol 51 and 1.9 billion 

gallons of MTBE 52 were blended into 

gasoline to supply the transportation 

sector with a total of 136 billion gallons 

of gasoline.53 A breakdown of the 2004 


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Gasoline by Grade, Formulation, PAD District, and 

State). 54Current California gasoline regualtions make it 

very difficult to meet the NOX emissions 

performance standard with ethanol content higher 

than about 6 vol%. For our analysis, all California 

RFG was assumed to contain 5.7 volume percent 

ethanol based on a conversation with Dean 

Simeroth at California Air Resources Board (CARB). 

55For the purpose of this analysis, except where 

noted, the term ‘‘RFG’’ pertains to Federal RFG plus 

California Phase 3 RFG (CaRFG3) and Arizona 

Clean Burning Gasoline (CBG). 

56 2004 MTBE consumption was obtained from 

EIA. The data received was limited to states with 

RFG programs, thus MTBE use was assumed to be 

limited to RFG areas for the purpose of this 

analysis. 

gasoline and oxygenate consumption by 

PADD is found below in Table VI–A.3– 

1. 

PADD is found below in Table VI–A.3– 

1. 

TABLE VI.A.3–1.—2004 U.S. GASOLINE & OXYGENATE CONSUMPTION BY PADD 

PADD Gasoline 

MMgal 

Ethanol MTBEa

MMgal Percent of 

gasoline MMgal Percent of gasoline 

PADD 1 .................................................................................................... 49,193 660 1.3 1,360 2.8 

PADD 2 .................................................................................................... 38,789 1,616 4.2 1 0.0 

PADD 3 .................................................................................................... 20,615 79 0.4 498 2.4

PADD 4 .................................................................................................... 4,542 83 1.8 0 0.0 

PADD 5 b .................................................................................................. 7,918 209 2.6 19 0.2 

California .................................................................................................. 14,836 853 5.8 0 0.0 

Total .................................................................................................. 135,893 3,500 2.6 1,878 1.4 

a MTBE blended into RFG. 

bPADD 5 excluding California. 

As shown above, nearly half (or about 

45 percent) of the ethanol was 

consumed in PADD 2 gasoline, where 

the majority of ethanol was produced. 

The next highest region of use was the 

State of California which accounted for 

about 25 percent of domestic ethanol 

consumption. This is reasonable 

because California alone accounts for 

over 10 percent of the nation’s total 

gasoline consumption and all the fuel 

(both Federal RFG and California Phase 

3 RFG) has been assumed to contain 

ethanol (following their recent MTBE 

ban) at 5.7 volume percent.54 The bulk 

of the remaining ethanol was used in 

reformulated gasoline (RFG) and winter 

oxy-fuel areas requiring oxygenated 

gasoline. Overall, 62 percent of ethanol 

was used in RFG, 33 percent was used 

in CG, and 5 percent was used in winter 

oxy-fuel.55

As shown above in Table VI.A.3–1, 99 

percent of MTBE use occurred in 

PADDs 1 and 3. This reflects the high 

concentration of RFG areas in the 

northeast (PADD 1) and the local 

production of MTBE in the gulf coast 

(PADD 3). PADD 1 receives a large 

portion of its gasoline from PADD 3 

refineries who either produce the fossilfuel based oxygenate or are closely 

affiliated with MTBE-producing 

petrochemical facilities in the area. 

Overall, 100 percent of MTBE in 2004 

was assumed to be used in reformulated 

gasoline.56

In 2004, total ethanol use exceeded 

MTBE use. Ethanol’s lead oxygenate 

role is relatively new, however the trend 

has been a progression over the past few 

years. From 2001 to 2004, ethanol 

consumption more than doubled (from 

1.7 to 3.5 billion gallons), while MTBE 

use (in RFG) was virtually cut in half 

(from 3.7 to 1.9 billion gallons). A plot 

of oxygenate use over the past decade is 

provided below in Figure VI.A.3–1. 

The nation’s transition to ethanol is 

linked to states’ responses to recent 

environmental concerns surrounding 

MTBE groundwater contamination. 

Resulting concerns over drinking water 

quality have prompted several states to 

significantly restrict or completely ban 

MTBE use in gasoline. At the time of 

this analysis, 19 states had adopted 

MTBE bans. A list of the states with 

MTBE bans is provided in RIA Table 

2.1–4. 


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57Energy Act Section 1504, promulgated on May 

8, 2006 at 71 FR 26691. 58Based on discussions with the refining 

industry. 

59 In AEO 2007, EIA is forecasted an even higher 

ethanol consumption of 11.2 billion gallons by 

2012. The draft report was issued on December 5, 

2006 and we could not incorporate it into the 

refinery modeling used to conduct our analyses. 

4. Expected Growth in Ethanol 

Consumption 

As mentioned above, ethanol demand 

is expected to increase well beyond the 

levels contained in the renewable fuels 

standard (RFS) under the Act. With the 

removal of the RFG oxygenate 

mandate,57 all U.S. refiners are taking 

steps to eliminate the use of MTBE as 

quickly as possible. In order to complete 

this transition quickly (by 2007 at the 

latest) while maintaining gasoline 

volume, octane, and mobile source air 

toxics emission performance standards, 

refiners have elected to blend ethanol 

into virtually all of their RFG.58 This has 

caused a dramatic increase in demand 

for ethanol which, in 2006, was met by 

temporarily shifting large volumes of 

ethanol out of conventional gasoline 

and into RFG areas. By 2012, however, 

ethanol production will have grown to 

accommodate the removal of MTBE 

without the need for such a shift from 

conventional gasoline. More important 

than the removal of MTBE over the long 

term, however, is the impact that the 

rise in crude oil price is having on 

demand for renewable fuels, both 

ethanol and biodiesel. This has 

dramatically improved the economics 

for renewable fuel use, leading to a 

surge in demand that is expected to 

continue. In the Annual Energy Outlook 

(AEO) 2006, EIA forecasted that by 

2012, total ethanol use (corn, cellulosic, 

and imports) would be about 9.6 billion 

gallons and biodiesel use would be 

about 0.3 billion gallons at a crude oil 

price forecast of $48 per barrel.59 This 

ethanol projection was not based on 

what amount the market would demand 

(which could be higher), but rather on 

the amount that could be produced by 

2012. Others are making similar 

predictions, and as discussed above in 

VI.A.2, production capacity would be 

sufficient. 

In assessing the impacts of expanded 

renewable fuel use, we have chosen to 

evaluate two different future ethanol 

consumption levels, one reflecting the 

statutory required minimum, and one 

reflecting the higher levels projected by 

EIA. For the statutory consumption 

scenario we assumed 6.7 billion gallons 

of ethanol use (0.25 billion gallons of 

which was assumed to be cellulosic) 

and 0.3 billion gallons of biodiesel. This 

figure is lower than the 7.2 billion 

gallons of ethanol we modeled in the 

proposal because it considers the 

renewable fuel equivalence values we 

are finalizing for corn ethanol (1), 

biodiesel (1.5) and cellulosic ethanol 

(2.5). For the higher projected renewable 

fuel consumption scenario, we assumed 

9.6 billion gallons of ethanol (0.25 

billion gallons of which was assumed to 

be cellulosic) and 0.3 billion gallons of 

biodiesel. Although the actual 

renewable fuel volumes consumed in 

2012 may differ from both the required 

and projected volumes, we believe that 


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these two scenarios provide a 

reasonable range for analysis purposes. 

For more information on how the 

renewable fuel usage scenarios we 

considered, refer to RIA Section 2.1. 

To estimate where ethanol would be 

consumed in 2012, we used a linear 

programming (LP) refinery cost model 

(discussed in more detail in Section 

VII). For both future ethanol 

consumption scenarios discussed above, 

the modeling provided us with a 

summary of ethanol usage by PADD, 

fuel type, and season. There was some 

post-processing involved to ensure that 

all state ethanol mandates and winter 

oxy-fuel requirements were satisfied. 

The adjusted results for the 6.7 Bgal RFS 

case and the 9.6 Bgal EIA case are 

presented below in Tables VI.A.4–1 and 

VI.A.4–2, respectively. 

TABLE VI.A.4–1.—FORECASTED 2012 U.S. ETHANOL CONSUMPTION (MMGAL) 6.7 BGAL RFS CASE

PADD 

Summer ethanol use Winter ethanol use Total 

ethanol CG a RFG b Total CG a RFG b Total 

PADD 1 ................................................................................ 399 679 1,078 350 706 1,057 2,134 

PADD 2 ................................................................................ 1,667 59 1,726 1,082 288 1,370 3,096 

PADD 3 ................................................................................ 161 47 208 146 0 146 354 

PADDs 4/5 c ......................................................................... 135 0 135 138 0 138 274 

California .............................................................................. 0 414 414 0 398 398 813 

Total .............................................................................. 2,362 1,200 3,562 1,717 1,392 3,109 6,671 

a Includes Arizona CBG and winter oxy-fuel. 

bFederal RFG and California Phase 3 RFG. 

cPADDS 4 and 5 excluding California. 

TABLE VI.A.4–1.—FORECASTED 2012 U.S. ETHANOL CONSUMPTION BY SEASON (MMGAL) 9.6 BGAL EIA CASE

PADD 

Summer ethanol use Winter ethanol use Total 

ethanol CG a RFG b Total CG a RFG b Total 

PADD1 ................................................................................. 610 630 1,240 267 973 1,240 2,481 

PADD2 ................................................................................. 1,735 185 1,919 1,631 366 1,998 3,917 

PADD3 ................................................................................. 901 47 949 856 0 856 1,805 

PADD 4/5 c ........................................................................... 339 0 339 154 0 154 492 

California .............................................................................. 0 435 435 0 470 470 905 

Total .............................................................................. 3,584 1,298 4,882 2,908 1,809 4,718 9,600 

a Includes Arizona CBG and winter oxy-fuel. 

bFederal RFG and California Phase 3 RFG. 

cPADDs 4 and 5 excluding California. 

As shown above, the LP modeling 

predicts that the majority of ethanol will 

be consumed in PADD 2, where most of 

the ethanol is produced. The results 

show varying levels of ethanol usage in 

RFG in response to the removal of the 

oxygenate requirement. For the higher 

ethanol consumption scenario, the 

modeling suggests that the majority of 

additional ethanol would be absorbed in 

PADD 3 conventional gasoline. With 

respect to seasonality, in both cases, the 

modeling predicts that a greater fraction 

of ethanol use would occur in the 

summertime due to the 1psi RVP 

waiver. For a more detailed discussion 

on future ethanol consumption, refer to 

Chapter 2 of the RIA. 

B. Overview of Biodiesel Industry and 

Future Production/Consumption 

1. Characterization of U.S. Biodiesel 

Production/Consumption 

Historically, the cost to make 

biodiesel was an inhibiting factor to 

production in the U.S. The cost to 

produce biodiesel was high compared to 

the price of petroleum derived diesel 

fuel, even with the subsidies and credits 

provided by federal and state programs. 

Much of the demand occurred as a 

result of mandates from states and local 

municipalities, that required the use of 

biodiesel. However, over the past couple 

of years biodiesel production has been 

increasing rapidly. The combination of 

higher crude oil prices and greater 

federal tax subsidies has created a 

favorable economic situation. The 

Biodiesel Blenders Tax Credit programs 

and the Commodity Credit Commission 

Bio-energy Program, both subsidize 

producers and offset production costs. 

The Energy Policy Act extended the 

Biodiesel Blenders Tax Credit program 

to 2008. This credit provides about one 

dollar per gallon in the form of a federal 

excise tax credit to biodiesel blenders 

from virgin vegetable oil feedstocks and 

50 cents per gallon to biodiesel 

produced from recycled grease and 

animal fats. The program was started in 

2004 under the American Jobs Act, 

spurring the expansion of biodiesel 

production and demand. Historical 

estimates and future forecasts of 

biodiesel production in the U.S. are 

presented in Table VI.B.1–1 below. 

TABLE VI.B.1–1.—ESTIMATED

BIODIESEL PRODUCTION

Year 

Million 

gallons 

per year 

2001 .............................................. 5 

2002 .............................................. 15 

2003 .............................................. 20 

2004 .............................................. 25 

2005 .............................................. 91 

2006 .............................................. 150 

2007 .............................................. 414 

2012 .............................................. 303 

Source: Historical data from 2001–2004 obtained from estimates from John Baize ‘‘ The 

Outlook and Impact of Biodiesel on the Oilseeds Sector’’ USDA Outlook Conference 06. 

Year 2005 data from USDA Bioenergy Program http://www.fsa.usda.gov/daco/bioenergy/ 

2005/FY2005ProductPayments, Year 2006 

data from verbal quote based on projection by 

NBB in June of 2006. Production data for 

years 2007 and higher are from EIA’s AEO 

2006. 

With the increase in biodiesel 

production, there has also been a 


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60NBB Survey September 13, 2006 ‘‘U.S. 

Biodiesel Production Capacity’’. 

61From Presentation ‘‘Biodiesel Production 

Capacity,’’ by Leland Tong, National Biodiesel 

Conference and Expo, February 7, 2006. 

62EIA Annual Energy Outlook 2006, Table 1. 63Enzyme Sugar Platform (ESP), Project Next 

Steps National Renewable Energy, Dan Schell, FY03 

Review Meeting; Laboratory Operated for the U.S. 

Department of Energy by Midwest Research 

Institute • B NREL, Golden, Colorado, May 1–2, 

2003; U.S. Department of Energy by Midwest 

Research Institute • Battelle • Bechtel. 

corresponding rapid expansion in 

biodiesel production capacity. 

Presently, there are 85 biodiesel plants 

in operation with an annual production 

capacity of 580 million gallons per 

year.60 The majority of the current 

production capacity was built in 2005 

and 2006, and was first available to 

produce fuel in the later part of 2005 

and in 2006. Though the capacity has 

grown, historically the biodiesel 

production capacity has far exceeded 

actual production with only 10–30 

percent of this being utilized to make 

biodiesel. The excess capacity, though, 

may be from biodiesel plants that do not 

operate full time and from production 

capacity that is primarily devoted to 

making esters for the ole-chemical 

markets, see Table VI.B.1–2. 

TABLE VI.B.1–2.—U.S. PRODUCTION CAPACITY HISTORY a

2001 2002 2003 2004 2005 2006 

Plants ....................................................................................................................................................... 9 11 16 22 45 85 

Capacity (million gal/yr) ........................................................................................................................... 50 54 85 157 290 580 

a Capacity Data based on surveys conducted around the month of September for most years, though the 2006 information is based on a survey conducted in January 2006.61

2. Expected Growth in U.S. Biodiesel 

Production/Consumption 

In addition to the 85 biodiesel plants 

already in production, as of early 2006, 

there were 65 plants in the construction 

phase and 13 existing plants that are 

expanding their capacity, which when 

completed would increase total 

biodiesel production capacity to over 

one billion gallons per year. Most of 

these plants should be completed by 

late 2007. As shown in Table VI.B.2–1 

if all of this capacity came to fruition, 

U.S. biodiesel capacity would exceed 

1.4 billion gallons. 

TABLE VI.B.2–1.—PROJECTED BIODIESEL PRODUCTION CAPACITY

Existing 

plants 

Construction 

phase 

Number of plants ..................................................................................................................................................... 85 78 

Total Plant Capacity, (MM Gallon/year) .................................................................................................................. 580 1,400 

For cost and emission analysis 

purposes, three biodiesel usage cases 

were considered: A 2004 base case, a 

2012 reference case, and a 2012 control 

case. The 2004 base case was formed 

based on historical biodiesel usage (25 

million gallons as summarized in Table 

VI.B.1.1). The reference case was 

computed by taking the 2004 base case 

and growing it out to 2012 by applying 

the 2004–2012 EIA diesel fuel growth 

rate.62 The resulting 2012 reference case 

consisted of 30 million gallons of 

biodiesel. Finally, for the 2012 control 

case, forecasted biodiesel use was 

assumed to be 300 million gallons based 

on EIA’s AEO 2006 report (rounded 

value from Table VI.B.1.1). Unlike 

forecasted ethanol use, biodiesel use 

was assumed to be constant at 300 

million gallons under both the statutory 

and higher projected renewable fuel 

consumption scenarios described in 

VI.A.4. EIA’s projection is based on the 

assumption that the blender’s tax credit 

is not renewed beyond 2008. If the tax 

credit is renewed, the projection for 

biodiesel demand would increase. 

C. Feasibility of the RFS Program 

Volume Obligations 

This section examines whether there 

are any feasibility issues associated with 

the meeting the minimum renewable 

fuel requirements of the Energy Act. 

Issues are examined with respect to 

renewable production capacity, 

cellulosic ethanol production capacity, 

and distribution system capability. Land 

resource requirements are discussed in 

Chapter 7 of the RIA. 

1. Production Capacity of Ethanol and 

Biodiesel 

As shown in Sections VI.A. and VI.B., 

increases in renewable fuel production 

capacity are already proceeding at a 

pace significantly faster than required to 

meet the 2012 mandate in the Act of 7.5 

billion gallons as well as the mandate 

(starting in 2013) of a minimum of 250 

million gallons of cellulosic ethanol. 

The combination of ethanol and 

biodiesel plants in existence and 

planned or under construction is 

expected to provide a total renewable 

fuel production capacity of over 9.6 

billion gallons by the end of 2012. 

Production capacity is expected to 

continue to increase in response to 

strong demand. We estimate that this 

will require a maximum of 2,100 

construction workers and 90 engineers 

on a monthly basis through 2012. 

2. Technology Available To Produce 

Cellulosic Ethanol 

There are a wide variety of 

government and renewable fuels 

industry research and development 

programs dedicated to improving our 

ability to produce renewable fuels from 

cellulosic feedstocks. In this discussion, 

we deal with at least three completely 

different approaches to producing 

ethanol from cellulosic biomass. The 

first is based on what NREL refers to as 

the ‘‘sugar platform,’’ 63 which refers to 

pretreating the biomass, then 

hydrolyzing the cellulosic and 

hemicellulosic components into sugars, 

and then fermenting the sugars into 

ethanol. 

Corn grain is a nearly ideal feedstock 

for producing ethanol by fermentation, 

especially when compared with 

cellulosic biomass feedstocks. Corn 

grain is easily ground into small 

particles, following which the exposed 

starch which has a-linked saccharide 

polymers is easily hydrolyzed into 


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23962 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

64Appendix B, Overview of Cellulose-Ethanol 

Production Technology; OREGON CELLULOSEETHANOL STUDY, An evaluation of the potential 

for ethanol production in Oregon using cellulosebased feedstocks; Prepared by: Angela Graf, Bryan 

& Bryan Inc., 5015 Red Gulch, Cotopaxi, Colorado 

81223; Tom Koehler, Celilo Group, 2208 S.W. First 

Ave, #320, Portland, Oregon 97204; For submission 

to: The Oregon Office of Energy. 

65 Ibid. 

66 Ibid. 

67Technical and Economic Analysis Of An 

Enzymatic Hydrolysis Based Ethanol Plant, Fuels 

and Chemicals Research and Engineering Division, 

Solar Energy Research Institute, Golden CO, 80401, 

June 1991 • DRAFT • SERI Protected Proprietary 

Information • Do Not Copy. 

68Biomass to Ethanol Process Evaluation, A 

report prepared for National Renewable Energy 

Laboratory, December 1994; Chem Systems Inc. 303 

South Broadway, Tarrytown, New York, 10591. 

69Lignocellulosic Biomass to Ethanol Process 

Design and Economics Utilizing Co-Current Dilute 

Acid Prehydrolysis and Enzymatic Hydrolysis 

Current and Futuristic Scenarios, July 1999 • NREL/ 

TP–580–26157; Robert Wooley, Mark Ruth, John 

Sheehan, and Kelly Ibsen, Biotechnology Center for 

Fuels and Chemicals; Henry Majdeski and Adrian 

Galvez, Delta-T Corporation; National Renewable 

Energy Laboratory, 1617 Cole Boulevard, Golden, 

Colorado 80401–3393; NREL is a U.S. Department 

of Energy Laboratory Operated by Midwest 

Research Institute • Battelle • Bechtel; Contract No. 

DE–AC36–98–GO10337. 

simple, single component sugar which 

can then be easily fermented into 

ethanol. By comparison, the biomass 

lignin structure must be either 

mechanically or chemically broken 

down to permit hydrolyzing chemicals 

and enzymes access to the saccharide 

polymers. The central problem is that 

the cellulose/hemicellulose saccharide 

polymers are b-linked which makes 

hydrolysis much more difficult. Simple 

microbial fermentation used in corn 

sugar fermentation is also not possible, 

since the cellulose and hemicellulose (6 

& 5 carbon molecules, respectively) 

have not been able to be fermented by 

the same microbe. We discuss various 

pretreatment, hydrolysis and 

fermentation technologies, below. The 

second and third approaches have 

nothing to do with pretreatment, acids, 

enzymes, or fermentation. The second is 

sometimes referred to as the ‘‘syngas’’ or 

‘‘gas-to-liquid’’ approach; we will call it 

the ‘‘Syngas Platform.’’ Briefly, the 

cellulosic biomass feedstock is steamreformed to produce syngas which is 

then converted to ethanol over a 

Fischer-Tropsch catalyst. The third 

approach uses plasma technology. 

a. Sugar Platform 

Plant cell walls are made up of 

cellulose and hemicellulose polymers 

embedded in a lignin matrix. This 

complex structure prevents both the 

first step, hydrolyzation of the cellulose 

and hemicellulose polymers, and the 

second step, fermentation of the 

hydrolyzed sugars into ethanol. 

i. Pretreatment 

Those who wish to use cellulosic 

biomass feedstocks to produce ethanol 

face several, difficult problems. The 

lignin sheath, present in all cellulosic 

materials, prevents, or at the very least, 

severely restricts hydrolysis. To produce 

ethanol from cellulosic biomass 

feedstocks by fermentation, some type 

of thermo-mechanical, mechanical, 

chemical or a combination of these 

pretreatments is always necessary before 

the cellulosic and hemicellulosic 

polymers can be hydrolyzed. In effect, 

the lignin structure must be ‘‘opened’’ to 

allow efficient and effective strong acid 

hydrolysis, weak acid hydrolysis, or 

weak acid enzymatic hydrolysis of the 

cellulose/hemicellulose to their glucose 

and xylose sugar components. Over 

time, many pretreatment methods or 

combinations of methods have been 

tried, some with more success than 

others. Usually, intense physical 

pretreatments such as steam explosion 

are required; grasses and forest 

thinnings usually need to be chipped, 

prior to chemical or enzymatic 

hydrolysis. The most common chemical 

pretreatments for cellulosic feedstocks 

are strong acid, dilute acid, caustic, 

organic solvents, ammonia, sulfur 

dioxide, carbon dioxide or other 

chemicals which make the biomass 

more accessible to the enzymes. 

Following pretreatment, acidic (dilute 

and concentrated) and enzymatic 

hydrolysis are the two process types 

commonly used to hydrolyze cellulosic 

feedstocks before fermentation into 

ethanol.64

ii. Dilute Acid Hydrolysis 

Dilute acid hydrolysis is the oldest 

technology for converting cellulose 

biomass to ethanol. The dilute acid 

process uses a 1-percent sulfuric acid in 

a continuous flow reactor at about 

420 °F; reaction times are measured in 

seconds and minutes, which facilitates 

continuous processing. The process 

involves two reactions with a sugar 

conversion efficiency of about 50 

percent. The process conditions at 

which the cellulosic molecules are 

converted into sugar are also those at 

which the sugar is almost immediately 

converted into other chemicals, 

principally furfural. The rapid 

conversion to furfural reduces the sugar 

yield, which along with other byproducts inhibits the fermentation 

process. One way to decrease sugar 

degradation is to use a two-stage process 

which takes advantage of the fact that 

hemicellulose (5-carbon) sugars degrade 

more rapidly than cellulose (6-carbon) 

sugars. The first stage is conducted 

under mild process conditions to 

recover the 5-carbon sugars, while the 

second stage is conducted under harsher 

conditions to recover the 6-carbon 

sugars. Both hydrolyzed solutions are 

then fermented to ethanol. Lime is used 

to neutralize the residual acid before the 

fermentation stage. Regardless, some 

sugar degrades to furfural, which 

naturally limits the net yield of ethanol. 

The residual cellulose and lignin are 

used as boiler fuel for electricity or 

steam production.65

iii. Concentrated acid hydrolysis 

Concentrated acid hydrolysis uses a 

70-percent sulfuric acid solution, 

followed by water hydrolysis to convert 

the cellulose into sugar. The process 

rapidly, and nearly completely, converts 

cellulose to glucose (6-carbon) and 

hemicellulose to xylose (5-carbon) 

sugar, with little degradation to furfural; 

the reaction times are typically slower 

than those of the dilute acid process. 

The critical factors needed to make this 

process economically viable are to 

optimize sugar recovery and cost 

effectively recover the acid for 

recycling. The concentrated acid 

process is somewhat more complicated 

and requires more time, but it has the 

primary advantage of yielding up to 

about 90% of both hemicellulosic and 

cellulosic sugars.66 In addition, a 

significant advantage of the 

concentrated acid process is that it is 

carried out at relatively low 

temperatures, about 212 °F, and low 

pressure, such that fiberglass reactors 

and piping can be used. 

iv. Enzymatic hydrolysis 

Enzymatic hydrolysis is not 

necessarily a recent discovery. We 

found reports of research conducted by 

a variety of companies and government 

agencies going back to at least 

1991. 67 68 69 The enzymatic hydrolysis 

of cellulose was reportedly discovered 

when a fungus, trichoderma reesei, was 

identified which produced cellulase 

enzymes that broke down cotton 

clothing and tents in the South Pacific 

during World War II. Since then, 

generations of cellulases have been 

developed through genetic 

modifications of the fungus strain. As in 

acid hydrolysis, the hydrolyzing 

enzymes must have access to the 

cellulose and hemicellulose in order to 

work efficiently. Although enzymatic 

hydrolysis requires some kind of 

pretreatment, purely physical 

pretreatments are typically not 

adequate. Furthermore, the chemical 

method uses dilute sulfuric acid, which 

is poisonous to the fermentation 


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70 Ibid. 

71 Gridley Ethanol Demonstration Project 

Utilizing Biomass Gasification Technology: Pilot 

Plant Gasifier and Syngas Conversion Testing, 

August 2002–June 2004; February 2005 • NREL/SR– 

510–37581; TSS Consultants, For the City of 

Gridley, California, 1617 Cole Boulevard, Golden, 

Colorado 80401–3393, 303–275–3000 • http:// 

www.nrel.gov; Operated for the U.S. Department of 

Energy Office of Energy Efficiency and Renewable 

Energy by Midwest Research Institute • Battelle 

Contract No. DE–AC36–99–GO10337. 

72Ethanol From Tires Via Plasma Converter Plus 

Fischer Tropsch, March 15, 2006; http:// 

thefraserdomain.typepad.com/energy/2006/03/ 

ethanol_from_ti.html. 

73Wheat Straw for Ethanol Production in 

Washington: A Resource, Technical, and Economic 

Assessment, September 2001, WSUCEEP2001084; 

Prepared by: James D. Kerstetter, Ph.D., John Kim 

Lyons, Washington State University Cooperative 

Extension Energy Program, 925 Plum Street, SE., 

P.O. Box 43165, Olympia, WA 98504–3165; 

Prepared for: Washington State Office of Trade and 

Economic Development. 

microorganisms and must be detoxified. 

While original enzymatic hydrolysis 

processes used separate hydrolysis and 

fermentation steps, recent process 

improvements integrate saccharification 

and fermentation by combining the 

cellulase enzymes and fermenting 

microbes in one vessel. This results in 

a one-step process of sugar production 

and fermentation, referred to as the 

simultaneous saccharification and 

fermentation (SSF) process. One 

disadvantage is that the cellulase 

enzyme and fermentation organism 

must operate under the same process 

conditions, which could decrease the 

sugar and, ultimately, the ethanol 

yields. An alternative to the SSF 

technology is the sequential hydrolysis 

and fermentation (SHF) process. The 

separation of hydrolysis and 

fermentation enables enzymes to 

operate at higher temperatures in the 

hydrolysis step to increase sugar 

production and more moderate 

temperatures in the fermentation step to 

optimize the conversion of sugar into 

ethanol. 

Cost-effective cellulase enzymes must 

also be developed for this technology to 

be completely successful.70 Several 

companies are using variations of these 

technologies to develop processes for 

converting cellulosic biomass into 

ethanol by way of fermentation. A few 

groups, using recently developed 

genome modifying technology, have 

been able to produce a variety of new 

or modified enzymes and microbes that 

show promise for use in weak- or diluteacid enzymatic-prehydrolysis. Another 

problem with cellulosic feedstocks is, as 

previously described, that the 

hydrolysis reactions produce both 

glucose, the six-carbon sugar, and 

xylose, the five-carbon sugar (pentose 

sugar, C5H10O5; sometimes called ‘‘wood 

sugar’’). Early conversion technology 

required different microbes to ferment 

each sugar. Recent research has 

developed better fermenting organisms. 

Now, glucose and xylose can be cofermented—hence, the present-day 

terminology: Weak-acid enzymatic 

hydrolysis and co-fermentation. 

b. Syngas Platform 

The second platform for producing 

cellulosic ethanol is to convert the 

biomass into a syngas which is then 

converted into ethanol. A ‘‘generic’’ 

syngas process is essentially a ‘‘steam 

reformer,’’ which ‘‘gasifies’’ biomass 

and other carbon based substances 

including wastes, in a reduced-oxygen 

environment and reacts them with 

steam to produce a synthesis gas or 

‘‘syngas’’ consisting primarily of carbon 

monoxide and hydrogen. The syngas is 

then passed over in a Fischer-Tropsch 

catalyst to produce ethanol. 

The biomass feedstock is dried to 

about 15% moisture content and ground 

small enough to be efficiently burned 

and reacted in the reformer. The 

reformer, an important upstream 

element of the process, is essentially a 

common solid-fuel gasifier, which with 

some modification and steam injection 

becomes what is sometimes referred to 

as the ‘‘primary reformer.’’ 

When any fuel is completely burned, 

all of its potential energy is released as 

heat which can be recovered for 

immediate use. In a common 

gasification process, the partially 

burned fuel (wood or coal) releases a 

small amount of heat, but leaves some 

uncombusted, gaseous products. 

Ordinarily, the hot product gases are fed 

directly to a nearby boiler or gas turbine, 

to do work; it has been reported that for 

a well-designed system, the overall 

efficiency may approach that of a solid 

fuel boiler. However, when steam is 

injected into the gasifier, it reacts with 

the burning solid fuel to produce more 

gaseous product. The primary reaction 

is between carbon and water which 

produces hydrogen and carbon 

monoxide and an inorganic ash. The ash 

and heavy hydrocarbon-tars are 

removed from the raw syngas before it 

is compressed and passed over FisherTropsch catalyst to produce ethanol. 

Fisher-Tropsch technology has been 

used for many years in the chemical and 

refining industries, most notably to 

produce gasoline and diesel fuel from 

syngas produced by coal gasification. 

Whether the Fischer-Tropsch reaction 

produces diesel or ethanol is primarily 

the result of changes to process 

pressure, temperature and in some cases 

the use of custom catalysts. In most 

cases, the Fischer-Tropsch process did 

not produce pure ethanol in the first 

pass through the system. Rather, a 

stream of mixed chemicals was 

produced, including gasoline, diesel, 

and oxygenated hydrocarbons 

(alcohol).71

c. Plasma Technology 

The development of another 

technology, called plasma, is also 

underway for creating a syngas from 

which ethanol is produced. A plasma 

‘‘reactor,’’ generates an ionized gas 

(plasma) which serves as an electrical 

conductor to transfer intense radiant 

energy to a biomass or waste material. 

This intense energy is said to actually 

breakdown the various materials in the 

biomass or waste into their atomic 

components. Anything present in the 

feed-mass that doesn’t gasify, is 

essentially ‘‘vitrified.’’ This vitrified 

stream is reportedly inert and can be 

used as aggregate in paving materials. 

Following gasification, the syngas is 

cooled, impurities are removed, and the 

gas is sent to ethanol production as with 

the syngas platform described above.72

d. Feedstock Optimization 

Cellulosic biomass can come from a 

variety of sources. Because the 

conversion of cellulosic biomass to 

ethanol has not yet been commercially 

demonstrated, we cannot say at this 

time which feedstocks are superior to 

others. A few of the many resources are: 

Post-sorted municipal waste, rice and 

wheat straw,73 soft-woods, hardwood, 

switch grass, and bagasse. Regardless, 

each feedstock requires a specific 

combination of pretreatment methods 

and enzyme ‘‘cocktails’’ to optimize the 

operation and maximize the ethanol 

yield. One of the many challenges for 

the cellulose-ethanol industry is to find 

the best feedstocks and then develop the 

most cost-effective ways for converting 

them into ethanol. 

3. Renewable Fuel Distribution System 

Capability 

Ethanol and biodiesel blended fuels 

are currently not shipped by petroleum 

product pipeline due to operational 

issues and additional cost factors. 

Hence, a separate distribution system is 

needed for ethanol and biodiesel up to 

the point where they are blended into 

petroleum-based fuel as it is loaded into 

tank trucks for delivery to retail and 

fleet operators. In cases where ethanol 

and biodiesel are produced within 200 

miles of a terminal, trucking is often the 

preferred means of distribution. For 

longer shipping distances, the preferred 


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23964 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

74 ‘‘Infrastructure Requirements for an Expanded 

Fuel Ethanol Industry,’’ Downstream Alternatives 

Inc., January 15, 2002. 

75 Kwaitkowski, J.R., McAloon, A., Taylor, F., 

Johnston, D.B., Industrial Crops and Products 23 

(2006) 288–296. 

76Shapouri, H., Gallagher, P., USDA’s 2002 

Ethanol Cost-of-Production Survey (published July 

2005). 

method of bringing renewable fuels to 

terminals is by rail and barge. 

Modifications to the rail, barge, tank 

truck, and terminal distribution systems 

will be needed to support the transport 

of the anticipated increased volumes of 

renewable fuels. These modifications 

include the addition of terminal 

blending systems for ethanol and 

biodiesel, additional storage tanks at 

terminals, additional rail delivery 

systems at terminals for ethanol and 

biodiesel, and additional rail cars, 

barges, and tank trucks to distribute 

ethanol and biodiesel to terminals. 

Terminal storage tanks for 100 percent 

biodiesel will also need to be heated 

during cold months to prevent gelling. 

The most comprehensive study of the 

infrastructure requirements for an 

expanded fuel ethanol industry was 

conducted for the Department of Energy 

(DOE) in 2002.74 The conclusions 

reached in that study indicate that the 

changes needed to handle the 

anticipated increased volume of ethanol 

by 2012 will not represent a major 

obstacle to industry. While some 

changes have taken place since this 

report was issued, including an 

increased reliance on rail over marine 

transport, we continue to believe that 

the rail and marine transportation 

industries can manage the increased 

growth in demand in an orderly fashion. 

This belief is supported by the 

demonstrated ability for the industry to 

handle the rapid increases and 

redistribution of ethanol use across the 

country over the last several years as 

MTBE was removed. The necessary 

facility changes at terminals and at retail 

stations to dispense ethanol containing 

fuels have been occurring at a record 

pace. Given that future growth is 

expected to progress at a steadier pace 

and with greater advance warning in 

response to economic drivers, we 

anticipate that the distribution system 

will be able to respond appropriately. A 

discussion of the costs associated 

making the changes discussed above is 

contained in Section VII.B of today’s 

preamble. 

VII. Impacts on Cost of Renewable 

Fuels and Gasoline 

This section examines the impact on 

fuel costs resulting from the growth in 

renewable fuel use between a base year 

of 2004 and 2012. We note that based 

on analyses conducted by the Energy 

Information Administration (EIA), 

renewable fuels will be used in gasoline 

and diesel fuel in excess of the RFS 

requirements. As such, the changes in 

the use of renewable fuels and their 

related cost impacts are not directly 

attributable to the RFS rule. Rather, our 

analysis assesses the broader fuels 

impacts of the growth in renewable fuel 

use in the context of corresponding 

changes to the makeup of gasoline. 

These fuel impacts include the 

elimination of the reformulated gasoline 

(RFG) oxygen standard which has 

resulted in the refiners ceasing to use 

the gasoline blendstock methyl tertiary 

butyl ether (MTBE) and replacing it 

with ethanol. Thus, in this analysis, we 

are assessing the impact on the cost of 

gasoline and diesel fuel of increased use 

of renewable fuels, the cost savings 

resulting from the phase out of MTBE 

and the increased cost due to the other 

changes in fuel quality that result. 

As discussed in Section II, we chose 

to analyze a range of renewable fuel use. 

In the case of ethanol’s use in gasoline, 

the lower end of this range is based on 

the minimum renewable fuel volume 

requirements in the Act, (the RFS case) 

and the higher end is based on AEO 

2006 (the EIA case). At both ends of this 

range, we assume that biodiesel 

consumption will be the level estimated 

in AEO 2006. We analyzed the projected 

fuel consumption scenario and 

associated program costs in 2012, the 

year that the RFS is fully phased-in. The 

volumes of renewable fuels consumed 

in 2012 at the two ends of the range are 

summarized in Table II.A.1–1. 

We have estimated an average corn 

ethanol production cost of $1.26 per 

gallon in 2012 (2004 dollars) for the RFS 

case and $1.32 per gallon for the EIA 

case. For cellulosic ethanol, we estimate 

it will cost approximately $1.65 in 2012 

(2004 dollars) to produce a gallon of 

ethanol using corn stover as a cellulosic 

feedstock. In this analysis, however, we 

assume that the cellulosic requirement 

will be met by corn-based ethanol 

produced by energy sourced from 

biomass (animal and other waste 

materials as discussed in Section III.B of 

today’s preamble) and costing the same 

as corn based ethanol produced by 

conventional means. 

We estimated production costs for 

soy-derived biodiesel of $2.06 per gallon 

in 2004 and $1.89 per gallon in 2012. 

For yellow grease derived biodiesel, we 

estimate an average production cost of 

$1.19 per gallon in 2004 and $1.11 in 

2012. 

For the proposed rule, we estimated 

the cost of increased use of renewable 

fuel and other major cost impacts by 

developing our own cost spreadsheet 

model. That analysis considered the 

production cost, distribution cost as 

well as the cost for balancing the octane 

and RVP caused by these fuel changes. 

That analysis, however, could not 

properly balance octane and other 

gasoline qualities. For this final rule, we 

have therefore used the services of 

Jacobs Consultancy to run their refinery 

LP model to estimate the cost impacts 

of the RFS rule. 

The results from the refinery LP 

model indicate that the impacts on 

overall gasoline costs from the increased 

use of ethanol and the corresponding 

changes to the other aspects of gasoline 

would be 0.49 cents per gallon for the 

RFS case. The EIA case would result in 

increased total cost of 1.03 cents per 

gallon. The actual cost at the fuel pump, 

however, will be decreased due to the 

effect of State and Federal tax subsidies 

for ethanol. Taking this into 

consideration results in ‘‘at the pump’’ 

decreased costs (cost savings) of ¥0.47 

cents per gallon for the RFS case and ‘‘at 

the pump’’ decreased cost of ¥0.83 

cents per gallon for the EIA case. 

Section 7 of the RIA contains more 

detail on the cost analysis used to 

develop these costs. 

A. Renewable Fuel Production and 

Blending Costs 

1. Ethanol Production Costs 

a. Corn Ethanol 

A significant amount of work has 

been done in the last decade on 

surveying and modeling the costs 

involved in producing ethanol from 

corn to serve business and investment 

purposes as well as to try to educate 

energy policy decisions. Corn ethanol 

costs for our work were estimated using 

a model developed by USDA in the 

1990s that has been continuously 

updated by USDA. The most current 

version was documented in a peerreviewed journal paper on cost 

modeling of the dry-grind corn ethanol 

process, and it produces results that 

compare well with cost information 

found in surveys of existing plants.75 76

We made some minor modifications to 

the USDA model to allow scaling of the 

plant size, to allow consideration of 

plant energy sources other than natural 

gas, and to adjust for energy prices in 

2012, the year of our analysis. 

The cost of ethanol production is 

most sensitive to the prices of corn and 

the primary co-product, DDGS. Utilities, 

capital, and labor expenses also have an 

impact, although to a lesser extent. Corn 

feedstock minus DDGS sale credits 


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77For more details on fuel sources and costs of 

production, see RIA Chapter 1.2.2 and 7.1.1.2. 

78Whims, J., Sparks Companies, Inc. and Kansas 

State University, ‘‘Corn Based Ethanol Costs and 

Margins, Attachment 1’’ (Published May 2002). 

79Piel, W.J., Tier & Associates, Inc., March 9, 

2006 report on costs of ethanol production and 

alternatives. 

80Energy Policy Act of 2005, Section 1501 

amending Clean Air Act Section 211(o)(1)(A). 

81See Table VI.A.1–2 for more details on number 

of operating ethanol plants and their fuel sources. 

82Lignocellulosic Biomass to Ethanol Process 

Design and Economics Utilizing Co-Current Dilute 

Acid Prehydrolysis and Enzymatic Hydrolysis 

Current and Futuristic Scenarios, Robert Wooley, 

Mark Ruth, John Sheehan, and Kelly Ibsen, 

Biotechnology Center for Fuels and Chemicals, 

Henry Majdeski and Adrian Galvez, Delta-T 

Corporation; National Renewable Energy 

Laboratory, Golden, CO, July 1999, NREL/TP–580– 

26157. 

83 Determining the Cost of Producing Ethanol 

from Corn Starch and Lignocellulosic Feedstocks; A 

Joint Study Sponsored by: USDA and USDOE, 

October 2000 • NREL/TP–580–28893 • Andrew 

McAloon, Frank Taylor, Winnie Yee, USDA, 

Eastern Regional Research Center Agricultural 

Research Service; Kelly Ibsen, Robert Wooley, 

National Renewable Energy Laboratory, 

Biotechnology Center for Fuels and Chemicals, 

1617 Cole Boulevard, Golden, CO, 80401–3393; 

NREL is a USDOE Operated by Midwest Research 

Institute • Battelle • Bechtel; Contract No. DE– 

AC36–99–GO10337. 

represents about 48% of the final pergallon cost, while utilities, capital and 

labor comprise about 19%, 9%, and 6%, 

respectively. For this work, we used 

corn prices of $2.50/bu and $2.71/bu for 

the RFS and EIA cases, respectively, 

with corresponding DDGS prices at 

$83.35/ton and $85.16/ton (2004 

dollars). These estimates are from 

modeling work done for this rulemaking 

using the Forestry and Agricultural 

Sector Optimization Model, which is 

described in more detail in Chapter 8 of 

the RIA. Energy prices were derived 

from historical data and projected to 

2012 using EIA’s AEO 2006. More 

details on how the ethanol production 

cost estimates were made can be found 

in Chapter 7 of the RIA. 

The estimated average corn ethanol 

production cost of $1.26 per gallon in 

2012 (2004 dollars) in the RFS case and 

$1.32 per gallon in the EIA case 

represents the full cost to the plant 

operator, including purchase of 

feedstocks, energy required for 

operations, capital depreciation, labor, 

overhead, and denaturant, minus 

revenue from sale of co-products. It 

assumes that 86% of new plants will 

use natural gas as a thermal energy 

source, at a price of $6.16/MMBtu (2004 

dollars).77 It does not account for any 

subsidies on production or sale of 

ethanol. Note that the cost figure 

generated here is independent of the 

market price of ethanol, which has been 

related closely to the wholesale price of 

gasoline for the past decade.78 79

Under the Energy Act, starch-based 

ethanol can be counted as cellulosic if 

at least 90% of the process energy is 

derived from renewable feedstocks, 

which include plant cellulose, 

municipal solid waste, and manure 

biogas.80 It is expected that the vast 

majority of the 250 million gallons per 

year of cellulosic ethanol production 

required by 2013 will be made using 

this provision. While we have been 

unable to develop a detailed production 

cost estimate for corn ethanol meeting 

cellulosic criteria, we assume that the 

costs will not be significantly different 

from conventionally produced corn 

ethanol. We believe this is reasonable 

because the costs of hauling, storing, 

and processing this low or zero cost 

waste material in order to combust it 

will be significant, thus making overall 

production costs at these plants similar 

to gas-fired ethanol plants. As of the 

time of this writing, we know of only a 

few operating plants of this type, and 

expect the quantity of ethanol produced 

this way to remain a relatively small 

fraction of the total ethanol demand. 

Thus, the sensitivity of the overall 

analysis to this assumption is also very 

small.81 Based on these factors, we have 

assigned starch ethanol made using this 

cellulosic criteria the same cost as 

ethanol produced from corn using 

conventional means. 

b. Cellulosic Ethanol 

In 1999, the National Renewable 

Energy Laboratory (NREL) published a 

report outlining its work with the USDA 

to design a computer model of a plant 

to produce ethanol from hard-wood 

chips.82 Although the model was 

originally prepared for hardwood chips, 

it was meant to serve as a modifiableplatform for ongoing research using 

cellulosic biomass as feedstock to 

produce ethanol. Their long-term plan 

was that various indices, costs, 

technologies, and other factors would be 

regularly updated. 

NREL and USDA used a modified 

version of the model to compare the cost 

of using corn-grain with the cost of 

using corn stover to produce ethanol. 

We used the corn stover model from the 

second NREL/USDA study for the 

analysis for this rule. Because there 

were no operating plants that could 

potentially provide real world process 

design, construction, and operating data 

for processing cellulosic ethanol, NREL 

had considered modeling the plant 

based on assumptions associated with a 

first-of-a-kind or pioneer plant. The 

literature indicates that such models 

often underestimate actual costs since 

the high performance assumed for 

pioneer process plants is generally 

unrealistic. 

Instead, the NREL researchers 

assumed that the corn stover plant was 

an Nth generation plant, e.g., not a 

pioneer plant or first-or-its kind, built 

after the industry had been sufficiently 

established to provide verified costs. 

The corn stover plant was normalized to 

the corn kernel plant, e.g., placed on a 

similar basis.83 It is also reasonable to 

expect that the cost of cellulosic ethanol 

would be higher than corn ethanol 

because of the complexity of the 

cellulose conversion process. Recently, 

process improvements and 

advancements in corn production have 

considerably reduced the cost of 

producing corn ethanol. We also believe 

it is realistic to assume that cellulosederived ethanol process improvements 

will be made and that one can likewise 

reasonably expect that, as the industry 

matures, the cost of producing ethanol 

from cellulose will also decrease. 

We calculated fixed and variable 

operating costs using percentages of 

direct labor and total installed capital 

costs. Following this methodology, we 

estimate that producing a gallon of 

ethanol using corn stover as a cellulosic 

feedstock would cost $1.65 in 2012 

(2004 dollars). 

2. Biodiesel Production Costs 

We based our estimate for the cost to 

produce biodiesel on the use of USDA’s, 

NREL’s and EIA’s biodiesel computer 

models, along with estimates from 

engineering vendors that design 

biodiesel plants. Biodiesel fuel can be 

made from a wide variety of virgin 

vegetable oils such as canola, corn oil, 

cottonseed, etc. though, the operating 

costs (minus the costs of the feedstock 

oils) for these virgin vegetable oils are 

similar to the costs based on using soy 

oil as a feedstock, according to an 

analysis by NREL Biodiesel costs are 

therefore determined based on the use 

of soy oil, since this is the most 

commonly used virgin vegetable 

feedstock oil, and the use of recycled 

cooking oil (yellow grease) as a 

feedstock. Production costs are based on 

the process of continuous 

transesterification, which converts these 

feedstock oils to esters, along with the 

ester finishing processes and glycerol 

recovery. The models and vendors data 

are used to estimate the capital, fixed 

and operating costs associated with the 

production of biodiesel fuel, 

considering utility, labor, land and any 

other process and operating 

requirements, along with the prices for 


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84Based on EIA’s AEO 2006, 58.9 billion gallons 

of highway and off-road diesel fuel is projected to 

be consumed in 2012. 

85 Infrastructure Requirements for an Expanded 

Fuel Ethanol Industry, Downstream Alternatives 

Inc., January 15, 2002. 

feedstock oils, methanol, chemicals and 

the byproduct glycerol. 

The USDA, NREL and EIA models are 

based on a medium sized biodiesel 

plant that was designed to process raw 

degummed virgin soy oil as the 

feedstock. Additionally, the EIA model 

also contains a representation to 

estimate the biodiesel production cost 

for a plant that uses yellow grease as a 

feedstock. In the USDA model, the 

equipment needs and operating 

requirements for their biodiesel plant 

was estimated through the use of 

process simulation software. This 

software determines the biodiesel 

process requirements based on the use 

of established engineering relationships, 

process operating conditions and 

reagent needs. To substantiate the 

validity and accuracy of their model, 

USDA solicited feedback from major 

biodiesel producers. Based on 

responses, they then made adjustments 

to their model and updated their input 

prices to year 2005. The NREL model is 

also based on process simulation 

software, though the results are adjusted 

to reflect NREL’s modeling methods, 

using prices based on year 2002. The 

output for all of these models was 

provided in spreadsheet format. We also 

use engineering vendor estimates as 

another source to generate soy oil and 

yellow grease biodiesel production 

costs. These firms are primarily engaged 

in the business of designing biodiesel 

plants. 

The production costs are based on an 

average biodiesel plant located in the 

Midwest using feedstock oils and 

methanol, which are catalyzed into 

esters and glycerol by use of sodium 

hydroxide. Because local feedstock 

costs, distribution costs, and biodiesel 

plant type introduce some variability 

into cost estimates, we believe that 

using an average plant to estimate 

production costs provides a reasonable 

approach. Therefore, we simplified our 

analysis and used costs based on an 

average plant and average feedstock 

prices since the total biodiesel volumes 

forecasted are not large and represent a 

small fraction of the total projected 

renewable volumes. 

The models and vendor estimates are 

further modified to use input prices for 

feedstocks, byproducts and energy that 

reflect the effects of the fuels provisions 

in the Energy Act. In order to capture a 

range of production costs, we generated 

cost projections from all of the models 

and vendors. We present the details on 

these estimates in Chapter 7 of the RIA. 

For soy oil biodiesel production, we 

estimate a production cost ranging from 

$1.89 to $2.15 per gallon in 2012 (in 

2004 dollars) using these different 

models and sources of information. For 

yellow grease derived biodiesel, we 

used the EIA and vendor estimates to 

generate total production costs which 

range from $1.11 to $1.56 for year 2012. 

With the current Biodiesel Blender 

Tax Credit Program, producers using 

virgin vegetable oil stocks receive a one 

dollar per gallon tax subsidy while 

yellow grease producers receive 50 

cents per gallon, reducing the net 

production cost to a range of 89 to 115 

cents per gallon for soy oil and 61 to 106 

cents per gallon for yellow greased 

derived biodiesel fuel in 2012. This 

compares favorably to the projected 

wholesale diesel fuel prices of 138 cents 

per gallon in 2012, signifying that the 

economics for biodiesel are positive 

under the effects of the blender credit 

program, though the tax credit program 

will expire in 2008 if it is not extended. 

Congress may later elect to extend the 

blender credit program following the 

precedence used for extending the 

ethanol blending subsidies. 

Additionally, the Small Biodiesel 

Blenders Tax credit program and state 

tax and credit programs offer some 

additional subsidies and credits, though 

the benefits are modest in comparison to 

the Blender’s Tax credit. 

3. Diesel Fuel Costs 

Biodiesel fuel is blended into 

highway and nonroad diesel fuel, which 

increases the volume and therefore the 

supply of diesel fuel and thereby 

reduces the demand for refineryproduced diesel fuel. In this section, we 

estimate the overall cost impact, 

considering how much refinery based 

diesel fuel is displaced by the forecasted 

production volume of biodiesel fuel. 

The cost impacts are evaluated 

considering the production cost of 

biodiesel with and without the subsidy 

from the Biodiesel Blenders Tax credit 

program. Additionally, the diesel cost 

impacts are quantified with refinery 

diesel prices as forecasted by Jacob’s 

which is based on EIA’s AEO 2006. 

We estimate the net effect that 

biodiesel production has on overall cost 

for diesel fuel in year 2012 using total 

production costs for biodiesel and diesel 

fuel. The costs are evaluated based on 

how much refinery based diesel fuel is 

displaced by the biodiesel volumes as 

forecasted by EIA, accounting for energy 

density differences between the fuels. 

The cost impact is estimated from a 

2004 year basis, by multiplying the 

production costs of each fuel by the 

respective changes in volumes for 

biodiesel and estimated displaced diesel 

fuel. We further assume that all of the 

forecasted biodiesel volume is used as 

transport fuel, neglecting minor uses in 

the heating oil market. 

For RFS cases, the net effect of 

biodiesel production on diesel fuel 

costs, including the biodiesel blenders’ 

subsidy, is a reduction in the cost of 

transport diesel fuel costs by $114 

million per year, which equates to a 

reduction in fuel cost of about 0.20 

cents per gallon.84 Without the subsidy, 

the transport diesel fuel costs are 

increased by $91 million per year, or an 

increase of 0.16 cents per gallon for 

transport diesel fuel. 

B. Distribution Costs 

1. Ethanol Distribution Costs 

There are two components to the costs 

associated with distributing the volumes 

of ethanol necessary to meet the 

requirements of the Renewable Fuels 

Standard (RFS): (1) The capital cost of 

making the necessary upgrades to the 

fuel distribution infrastructure system, 

and (2) the ongoing additional freight 

costs associated with shipping ethanol 

to terminals. The most comprehensive 

study of the infrastructure requirements 

for an expanded fuel ethanol industry 

was conducted for the Department of 

Energy (DOE) in 2002.85 That study 

provided the foundation for our 

estimates of the capital costs associated 

with upgrading the distribution 

infrastructure system as well as the 

freight costs to handle the increased 

volume of ethanol needed to meet the 

requirements of the RFS in 2012. 

Distribution costs are evaluated here for 

both the RFS case and for the EIA case. 

The 2012 reference case against which 

we are estimating the cost of 

distributing the additional volume of 

ethanol needed to meet the 

requirements of the RFS is 3.9 billion 

gallons. 

a. Capital Costs To Upgrade Distribution 

System for Increased Ethanol Volume 

The 2002 DOE study examined two 

cases regarding the use of renewable 

fuels for estimating the capital costs for 

distributing additional ethanol. The first 

assumed that 5.1 billion gal/yr of 

ethanol would be used in 2010, and the 

second assumed that 10 billion gal/yr of 

ethanol would be used in the 2015 

timetable. We interpolated between 

these two cases to provide the 

foundation for our estimate of the 

capital costs to support the use of 6.7 

billion gal/yr of ethanol in 2012 for the 


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86See chapter 7.3 of the Regulatory Impact 

Analysis associated with today’s rule for additional 

discussion of how the results of the DAI study were 

adjusted to reflect current conditions in estimating 

the ethanol distribution infrastructure capital costs 

under today’s rule. 87For both the 6.7 bill gal/yr and 9.6 bill gal/yr 

cases, the baseline from which the DOE study cases 

were projected was adjusted to reflect a 3.9 bill gal/ 

yr 2012 baseline. 88This increased reliance on rail transport was 

the subject of a sensitivity analysis conducted for 

the proposed rule. 89These capital costs will be incurred 

incrementally during the period of 2007–2012 as 

ethanol volumes increase. For the purpose of this 

analysis, we assumed that all capital costs were 

incurred in 2007. 90Petroleum Market Model of the National Energy 

Modeling System, Part 2, March 2006, DOE/EIA– 

059 (2006), http://tonto.eia.doe.gov/FTPROOT/ 

modeldoc/m059(2006)-2.pdf. 

91See Chapter 7.3 of the RIA. 

92Hub terminals refer to those terminals where 

ethanol is delivered in large volume shipments 

such as by unit train (consisting of 70 tank cars or 

more) or marine barges/tanker. Satellite terminals 

are those terminals that are either supplied from a 

hub terminal or receive ethanol shipments in 

smaller quantities directly from the producer. See 

Chapter 7 of the RIA regarding how these estimates 

were adjusted from those in the proposal and the 

check of our estimates against current ethanol 

freight rates. 

93All capital costs were assumed to be incurred 

in 2007 and were amortized over 15 years at a 7 

percent cost of capital. 

94 2004 baseline of 25 million gallons grown with 

diesel demand to 2012. 

95See Chapter 1.3 of the Regulatory Impact 

Analysis associated with today’s rule for a 

discussion of the special handling requirements for 

biodiesel under cold conditions. 

96Biodiesel rail tank cars typically have a 

capacity of 25,500 gallons as opposed to 30,000 

gallons for an ethanol tank car. Thus, additional 

tank cars are needed to transport a given volume 

of biodiesel relative to the same volume of ethanol. 

97Capital costs will be incurred incrementally 

over the period of 2007–2012 as biodiesel volumes 

increase. For the purpose of this analysis, all capital 

costs were assumed to be incurred in 2007 and were 

amortized over 15 years at a 7 percent cost of 

capital. 

98The estimated ethanol freight costs were 

increased by 30 percent to arrive at the estimate of 

biodiesel freight costs. 

99See Section VII.A.2. of this preamble regarding 

biodiesel production costs. We estimated 2012 

production costs of $1.89 per gal for soy-derived 

biodiesel and $1.11 per gal for yellow grease 

derived biodiesel. 

RFS case.86 The 10 billion gal/yr case 

examined in the DOE study was used as 

the foundation in estimating the capital 

costs under the EIA projected case 

examined in today’s rule of 9.6 billion 

gal/yr of ethanol.87 Our estimated 

capital costs in this final rule differ from 

those in the proposed rule for several 

reasons. We adjusted our capital costs 

from those in the proposal to reflect an 

increase in the cost of tank cars and 

barges used to ship ethanol since the 

DOE study was conducted. In addition, 

we are assuming an increased reliance 

on rail transport over that projected in 

the DOE study.88

Table VII.B.1.a–1contains our 

estimates of the infrastructure changes 

and associated capital costs for the two 

ethanol use scenarios examined in 

today’s rule. Amortized over 15 years 

with a 7 percent cost of capital, the total 

capital costs equate to approximately 

1.4 cents per gallon of ethanol under the 

RFS case and 1.2 cents per gallon under 

the EIA case.89

TABLE VII.B.1.A–1.—ESTIMATED ETHANOL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS ($M) * 

RFS case 

6.7 Bgal/yr 

EIA case 

9.6 Bgal/yr 

Fixed Facilities: 

Retail ............. 20 44 

Terminals ...... 115 241 

Mobile Facilities: 

Transport 

Trucks ........ 24 50 

Barges ........... 21 43 

Rail Cars ....... 172 297 

Total Capital Costs 352 675 

* Relative to a 3.9 billion gal/yr reference 

case. 

b. Ethanol Freight Costs 

The Energy Information 

Administration (EIA) translated the 

ethanol freight cost estimates in the 

DOE study to a census division basis.90

For this final rule, we translated the EIA 

projections into State-by-State and 

national average freight costs to align 

with our State-by-State ethanol use 

estimates. Not including capital 

recovery, we estimate that the freight 

cost to transport ethanol to terminals 

would range from 4 cents per gallon in 

the Midwest to 25 cents per gallon to 

the West Coast. On a national basis, this 

averages to 11.3 cents per gallon of 

ethanol under the RFS case and 11.9 

cents per gallon under the EIA case.91

We adjusted the estimated ethanol 

freight costs from those in the proposal 

by increasing the cost of shipping 

ethanol to satellite versus hub terminals, 

by increasing the cost of gathering 

ethanol for large volume shipments to 

hub terminals, and by increasing the 

percentage of ethanol delivered to large 

volume terminals versus the volume 

delivered to lesser volume terminals.92

Including the cost of capital recovery 

for the necessary distribution facility 

changes, we estimate the national 

average cost of distributing ethanol to be 

12.7 cents per gallon under the RFS case 

and 13.1 cents per gallon under the EIA 

case.93 Thus, we estimate the total cost 

for producing and distributing ethanol 

to be between $1.39 and $1.45 per 

gallon of ethanol, on a nationwide 

average basis. This estimate includes 

both the capital costs to upgrade the 

distribution system and freight costs. 

2. Biodiesel Distribution Costs 

The volume of biodiesel used by 2012 

under the RFS is estimated at 300 

million gallons per year. The 2012 

baseline case against which we are 

estimating the cost of distributing the 

additional volume of biodiesel is 30 

million gallons.94

The capital costs associated with 

distribution of biodiesel are higher per 

gallon than those associated with the 

distribution of ethanol due to the need 

for storage tanks, blending systems, 

barges, tanker trucks and rail cars to be 

insulated and in many cases heated 

during the winter months.95 In the 

proposal, we estimated that these 

capital costs would be approximately 

$50,000,000. We adjusted our estimate 

of these capital costs for this final rule 

based on additional information 

regarding the cost to install necessary 

storage and blending equipment at 

terminals and the need for additional 

rail tank cars for biodiesel.96 As 

discussed in the RIA, we now estimate 

that handling the increased biodiesel 

volume will require a total capital cost 

investment of $145,500,000 which 

equates to about 6 cents per gallon of 

new biodiesel volume.97

In the proposal, we estimated that the 

freight costs for ethanol may adequately 

reflect those for biodiesel as well. In 

response to comments, we sought 

additional information regarding the 

freight costs for biodiesel. This 

information indicates that freight costs 

for biodiesel are typically 30 percent 

higher than those for ethanol which 

translates into an estimate of 15.5 cents 

per gallon for biodiesel freight costs on 

a national average basis.98

Including the cost of capital recovery 

for the necessary distribution facility 

changes, we estimate the cost of 

distributing biodiesel to be 21.5 cents 

per gallon. Depending on whether the 

feedstock is waste grease or virgin oil, 

we estimate the total cost for producing 

and distributing biodiesel to be between 

$1.33 and $2.11 per gallon of biodiesel, 

on a nationwide average basis.99 This 

estimate includes both the capital costs 

to upgrade the distribution system and 

freight costs, and the wide range reflects 

differences in different types of 

production feedstocks. 

C. Estimated Costs to Gasoline 

To estimate the cost of increased use 

of renewable fuels, the cost savings from 

the phase out of MTBE and the 

production cost of alkylate, we relied on 


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100EPA typically assesses social benefits and 

costs of a rulemaking. However, this analysis is 

more limited in its scope by examining the average 

cost of production of ethanol and gasoline without 

accounting for the effects of farm subsidies that 

tend to distort the market price of agricultural 

commodities. 

refinery modeling conducted by Jacob’s 

Consultancy that established baselines 

based on 2004 volumes, which were 

then used to project a reference case and 

2 control cases for 2012. The contractor 

developed a five region, U.S. demand 

model in which specific regional clean 

product demands are sold at 

hypothetical regional terminals. 

1. Description of Cases Modeled 

a. Base Case (2004) 

The baseline case was established by 

modeling fuel volumes for 2004, with 

data on fuel properties provided to the 

contractor by EPA. Fuel property data 

for this base case was built off of 2004 

refinery batch reports provided to EPA; 

however, the base case assumed sulfur 

standards based on gasoline data in 

2004, not with fully phased in Tier 2 

gasoline standards at the 30 ppm level. 

In addition we assumed the phase-in of 

15 ppm sulfur standards for highway, 

nonroad, locomotive and marine diesel 

fuel. The supply/demand balance for 

the U.S. was based on gasoline volumes 

from EIA and the California Air 

Resources Board (CARB). Our decision 

to use 2004 rather than 2005 as the 

baseline year was because of the 

refinery upset conditions associated 

with the Gulf Coast hurricanes in 2005. 

b. Reference Case (2012) 

The reference case was based on 

modeling the base case, using 2012 fuel 

prices, and scaling the 2004 fuel 

volumes to 2012 based on growth in fuel 

demand. In addition, we scaled MTBE 

and ethanol upward, in proportion to 

gasoline growth, and assumed the RFS 

program would not be in effect. For 

example, if the PADD 1 gasoline pool 

MTBE oxygen was 0.5 wt% in 2004, the 

reference case assumed it should remain 

at 0.5 wt%. Finally, we assumed the 

MSAT 1 standards would remain in 

place as would the RFG oxygen 

mandate. We assumed the crude slate 

quality in 2012 is the same as the 

baseline case. 

c. Control Cases (2012) 

Two control cases were run for 2012. 

The assumptions for each of the control 

cases are summarized below 

Control Case 1 (RFS case): 6.7 billion 

gallons/yr (BGY) of ethanol in gasoline; 

it reflects the renewable fuel mandate. 

We have also assumed that 0.3 billion 

gallons of biodiesel will be consumed as 

reflected in Table II.A.1–1. In addition, 

it is assumed that no MTBE is in 

gasoline, MSAT1 is in place, the psi 

waiver for conventional gasoline 

containing 10 volume percent ethanol is 

in effect, the RFS is in effect, and there 

is no RFG oxygenate mandate. 

Control Case 2 (EIA case): Same as 

Control Case 1, except the ethanol 

volume in gasoline is 9.6 BGY. 

2. Overview of Cost Analysis Provided 

by the Contractor Refinery Model 

The estimated cost of increased use of 

renewable fuels, the cost savings from 

the phase out of MTBE and the cost of 

converting some of the former MTBE 

feedstocks to produce alkylate, 

isooctane, and isooctene is provided by 

the output of the refinery model. As 

described in VII.C.1, the cost analysis 

was conducted by comparing the 2012 

reference case with the two control 

cases which are assumed to take place 

in 2012. 

The major factors which impact the 

costs in the refinery model are (1) 

blending in more ethanol, (2) adjusting 

the gasoline blending to lower RVP, (3) 

removing the MTBE, (4) converting 

MTBE feedstocks to other high quality 

replacement, and (5) adjusting for the 

change in gasoline energy density. The 

first is the addition of ethanol to the 

gasoline pool. The refinery model 

estimates the cost impact of increasing 

the volume of ethanol in the reference 

case from 3.94 billion gallons to 6.67 

and 9.60 billion gallons in the RFS and 

EIA modeled cases, respectively. The 

estimated production prices for ethanol 

for the RFS and EIA cases are provided 

above in Section VII.A. We also show 

the results with the federal and state 

subsidies applied to the production 

price of ethanol. 

The addition of ethanol to wintertime 

gasoline, and to summertime RFG, will 

cause an increase of approximately 1 psi 

in RVP which needs to be offset to 

maintain constant RVP levels. One 

method that refiners could choose to 

offset the increase in RVP is to reduce 

the butane levels in their gasoline. To 

some extent, the modeling results 

showed some occurrences of that, but it 

also did not report an overall increase 

in butane sales as a result of the 

increased use of ethanol. 

To convert the captive MTBE over to 

alkylate, after the rejection of methanol, 

refiners will need to combine refineryproduced isobutane with the 

isobutylene that was used as a feedstock 

for MTBE. The use of the isobutane will 

reduce the RVP of the gasoline pool 

from which it comes, helping to offset 

the RVP impacts of ethanol. Also, the 

increased production of alkylate 

provides a low RVP gasoline blendstock 

which offsets a portion of the cracked 

stocks produced by the fluidized 

catalytic cracker unit. Other means that 

the refinery model used to offset the 

high blending RVP of ethanol included 

purchasing gasoline components with 

lower RVP, producing more poly 

gasoline which has low RVP and selling 

more high-RVP naphtha to 

petrochemical sales. 

3. Overall Impact on Fuel Cost 

Based on the refinery modeling 

conducted for today’s rule, we have 

calculated the costs of these fuels 

changes that will occur for the RFS and 

EIA cases. The costs are expressed two 

different ways. First, we express the cost 

of the program without the ethanol 

consumption subsidies in which the 

costs are based on the total accumulated 

cost of each of the fuels changes. 

Second, we express the cost with the 

ethanol consumption subsidies 

included since the subsidized portion of 

the renewable fuels costs will not be 

represented to the consumer in its fuels 

costs paid at the pump, but instead by 

being paid through the state and federal 

tax revenues. In all cases, the capital 

costs are amortized at 7 percent return 

on investment (ROI), and based on 2006 

dollars. 

a. Cost Without Ethanol Subsidies 

Table VII.C.3.a–1 summarizes the 

costs without ethanol subsidies for each 

of the two control cases, including the 

cost for each aspect of the fuel changes, 

and the aggregated total and the pergallon costs for all the fuel changes.100

This estimate of costs reflects the 

changes in gasoline that are occurring 

with the expanded use of ethanol, 

including the corresponding removal of 

MTBE. These costs include the labor, 

utility and other operating costs, fixed 

costs and the capital costs for all the 

fuel changes expected. The per-gallon 

costs are derived by dividing the total 

costs over all U.S. gasoline projected to 

be consumed in 2012. We excluded 

federal and state ethanol consumption 

subsidies which avoids the transfer 

payments caused by these subsidies that 

would hide a portion of the program’s 

costs. 


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TABLE VII.C.3.A–1.—ESTIMATED COST WITHOUT ETHANOL CONSUMPTION SUBSIDIES

[Million dollars and cents per gallon; 7% ROI and 2006 dollars] 

RFS case 6.8 

billion gals incremental to 

reference case 

EIA case 9.6 

billion gals incremental to 

reference case 

EIA case 9.6 

billion gals incremental to 

RFS case 

Capital Costs ($MM) .................................................................................................................... ¥5,878 ¥7,311 ¥1,433 

Amortized Capital Costs ($MM/yr) .............................................................................................. ¥647 ¥804 ¥158 

Fixed Operating Cost ($MM/yr) ................................................................................................... ¥178 ¥222 ¥43 

Variable Operating Cost ($MM/yr) ............................................................................................... ¥201 ¥491 ¥290 

Fuel Economy Cost ($MM/yr) ...................................................................................................... 1,848 3,255 1407 

Total Cost ($MM/yr) .............................................................................................................. 823 1739 915 

Capital Costs (c/gal of gasoline) ................................................................................................. ¥0.40 ¥0.49 ¥0.10 

Fixed Operating Cost (c/gal of gasoline) ..................................................................................... ¥0.11 ¥0.14 ¥0.03 

Variable Operating Cost (c/gal of gasoline) ................................................................................ ¥0.12 ¥0.30 ¥0.18 

Fuel Economy Cost (c/gal of gasoline) ....................................................................................... 1.13 1.98 0.86 

Total Cost Excluding Subsidies (c/gal of gasoline) .............................................................. 0.50 1.06 0.56 

Our analysis shows that when 

considering all the costs associated with 

these fuel changes resulting from the 

expanded use of subsidized ethanol that 

these various possible gasoline use 

scenarios will increase fuel costs by 

$820 million or $1,740 million in the 

year 2012 for the RFS and EIA cases, 

respectively. Expressed as per-gallon 

costs, these fuel changes would increase 

fuel costs by 0.50 to 1.1 cents per gallon 

of gasoline. 

b. Gasoline Costs Including Ethanol 

Consumption Tax Subsidies 

Table VII.C.3.b–1 expresses the total 

and per-gallon gasoline costs for the two 

control scenarios with the federal and 

state ethanol subsidies included. The 

federal tax subsidy is 51 cents per gallon 

for each gallon of new ethanol blended 

into gasoline. The state tax subsidies 

apply in 5 states and range from 1.6 to 

29 cents per gallon. The cost reduction 

to the fuel industry and consumers is 

estimated by multiplying the subsidy 

times the volume of new ethanol 

estimated to be used in the state. The 

per-gallon costs are derived by dividing 

the total costs over all U.S. gasoline 

projected to be consumed in 2012. 

TABLE VII.C.3.B–1.—ESTIMATED COST INCLUDING ETHANOL CONSUMPTION SUBSIDIES

[Million dollars and cents per gallon; 7% ROI and 2006 dollars] 

RFS case 6.8 

billion gals incremental to 

reference case 

EIA case 9.6 

billion gals incremental to 

reference case 

EIA case 9.6 

billion gals incremental to 

RFS case 

Total Cost ($MM/yr) ..................................................................................................................... 823 1739 915 

Federal Subsidy ($MM/yr) ........................................................................................................... ¥1376 ¥2865 ¥1489 

State Subsidies ($MM/yr) ............................................................................................................ ¥5 ¥31 ¥26 

Revised Total Cost ($MM/yr) ............................................................................................... ¥558 ¥1158 ¥600 

Per-Gallon Cost Excluding Subsidies (c/gal of gasoline) ............................................................ 0.50 1.06 0.56 

Federal Subsidy (c/gal of gasoline) ............................................................................................. ¥0.84 ¥1.74 ¥0.90 

State Subsidies (c/gal of gasoline) .............................................................................................. ¥0.003 ¥0.02 ¥0.02 

Total Cost Including Subsidies (c/gal of gasoline) ............................................................... ¥0.34 ¥0.71 ¥0.37 

The cost including subsidies better 

represents gasoline’s production cost as 

reflected to the fuel industry as a whole 

and to consumers ‘‘at the pump’’ 

because the federal and state subsidies 

tend to hide a portion of the actual 

costs. Our analysis estimates that the 

fuel industry and consumers will see a 

0.34 and 0.71 cent per gallon decrease 

in the apparent cost of producing 

gasoline for the RFS and EIA cases, 

respectively. 

VIII. What Are the Impacts of Increased 

Ethanol Use on Emissions and Air 

Quality? 

In this section, we evaluate the impact 

of increased production and use of 

renewable fuels on emissions and air 

quality in the U.S., particularly ethanol 

and biodiesel. In performing these 

analyses, we compare the emissions 

which would have occurred in the 

future if fuel quality had remained 

unchanged from pre-Act levels to those 

which will be either required under the 

Energy Policy Act of 2005 (Energy Act 

or the Act) or exist due to market forces. 

This approach differs from that 

traditionally taken in EPA regulatory 

impact analyses. Traditionally, we 

would have compared future emissions 

with and without the requirement of the 

Energy Act. However, as described in 

Section II, we expect that total 

renewable fuel use in the U.S. in 2012 

to exceed the Act’s requirements even in 

the absence of the RFS program. Thus, 

a traditional regulatory impact analysis 

would have shown no impact on 

emissions or air quality. This is because, 

strictly speaking, if the same volume 

and types of renewable fuels are 

produced and used with and without 

the RFS program, the RFS program has 

no impact on fuel quality and thus, no 

impact on emissions or air quality. 

However, levels of renewable fuel use 

are increasing dramatically relative to 

both today and the recent past, with 

corresponding impacts on emissions 

and air quality. We believe that it is 

appropriate to evaluate these changes 

here, regardless of whether they are 

occurring due to economic forces or 

Energy Act requirements. 

In the process of estimating the 

impact of increased renewable fuel use, 

we also include the impact of reduced 

use of MTBE in gasoline. It is the 


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101Subject to funding. 102Refinery modeling performed in support of the 

original RFG rulemaking is also used to help 

separate the effects of the two oxygenates. 

increased production and use of ethanol 

which is facilitating the continued 

production of RFG which meets both 

commercial and EPA regulatory 

specifications without the use of MTBE. 

Because of this connection, we found it 

impractical to isolate the impact of 

increased ethanol use from the removal 

of MTBE. 

A. Effect of Renewable Fuel Use on 

Emissions 

1. Emissions From Gasoline Fueled 

Motor Vehicles and Equipment 

Several models of the impact of 

gasoline quality on motor vehicle 

emissions have been developed since 

the early 1990’s. We evaluated these 

models and selected those which were 

based on the most comprehensive set of 

emissions data and developed using the 

most advanced statistical tools for this 

analysis. Still, as will be described 

below, significant uncertainty exists as 

to the effect of these gasoline 

components on emissions from both 

motor vehicle and nonroad equipment, 

particularly from the latest vehicle and 

engine models equipped with the most 

advanced emission controls. Pending 

adequate funding, we plan to conduct 

significant vehicle and equipment 

testing over the next several years to 

improve our estimates of the impact of 

these additives and other gasoline 

properties on emissions. We hope that 

the results from these test programs will 

be available for reference in the future 

evaluations of the emission and air 

quality impacts of U.S. fuel programs 

required by the Act.101

The remainder of this sub-section is 

divided into three parts. The first 

evaluates the impact of increased 

ethanol use and decreased MTBE use on 

gasoline quality. The second evaluates 

the impact of increased ethanol use and 

decreased MTBE use on motor vehicle 

emissions. The third evaluates the 

impact of increased ethanol use and 

decreased MTBE use on nonroad 

equipment emissions. 

a. Gasoline Fuel Quality 

For the final rulemaking, we estimate 

the impact of increased ethanol use and 

decreased MTBE use on gasoline quality 

using refinery modeling conducted 

specifically for the RFS rulemaking.102

In general, adding ethanol to gasoline 

reduces the aromatic content of 

conventional gasoline and the mid- and 

high-distillation temperatures (e.g., T50 

and T90). RVP increases except in areas 

where ethanol blends are not provided 

a 1.0 RVP waiver of the applicable RVP 

standards in the summer. With the 

exception of RVP, adding MTBE 

directionally produces the same 

impacts. Thus, the effect of removing 

MTBE results in essentially the opposite 

impacts. Neither oxygenate is expected 

to affect sulfur levels, as refiners control 

sulfur independently in order to meet 

the Tier 2 sulfur standards. 

The impacts of oxygenate use are 

smaller with respect to RFG. This is due 

to RFG’s VOC and toxics emission 

performance specifications, which limit 

the range of feasible fuel quality values. 

Thus, oxygenate type or level does not 

consistently affect the RVP level and 

aromatic and benzene contents of RFG. 

Table VIII.A.1.a–1 shows the fuel 

quality of a typical summertime, nonoxygenated conventional gasoline and 

how these qualities change with the 

addition of 10 volume percent ethanol. 

Similarly, the table shows the fuel 

quality of a typical MTBE RFG blend 

and how fuel quality might change with 

either ethanol use or simply MTBE 

removal. All of these fuels are based, in 

whole or in part, on projections made by 

Jacobs in their recent refinery modeling 

performed for EPA and therefore, 

represent improvements over the 

projections made for the NPRM. Please 

see Chapter 2 of the RIA for a detailed 

description of the methodologies used 

to determine the specific changes in 

projected fuel quality. As discussed 

there, we use the Jacobs model 

projections of RFG fuel quality directly 

in our emission modeling. For 

conventional gasoline, we use the Jacobs 

modeling described in Section VII to 

determine the change in fuel quality due 

to ethanol use and apply this change to 

base fuel quality estimates contained in 

EPA’s NMIM emission inventory model. 

Sulfur is not shown in Table VIII.A.1.a– 

1, as it is held constant at 30 ppm, 

which is the average Tier 2 sulfur 

standard applicable to all gasoline sold 

in the U.S. in the timeframe of our 

emission analyses. 

TABLE VIII.A.1.A–1.—TYPICAL SUMMERTIME FUEL QUALITY

Fuel parameter 

Conventional gasoline Reformulated gasoline a

Typical 9 

RVP 

Ethanol 

blend MTBE blend Ethanol blend 

Nonoxygenated 

blend 

RVP (psi) ................................................................................................. 8.7 9.7 7.0 7.0 7.0 

T50 ........................................................................................................... 218 205 179 184 175 

T90 ........................................................................................................... 332 329 303 335 309 

E200 ......................................................................................................... 41 50 60 58 52 

E300 ......................................................................................................... 82 82 89 82 88 

Aromatics (vol%) ...................................................................................... 32 27 20 20 20 

Olefins (vol%) ........................................................................................... 7.7 7.7 4 14 15 

Oxygen (wt%) .......................................................................................... 0 3.5 2.1 3.5 0 

Benzene (vol%) ....................................................................................... 1.0 1.0 0.74 0.70 0.72 

a MTBE blend—Reference Case PADD 1 South, Ethanol blend—RFS Case PADD 1 North, Non-oxy blend. ¥RFS Case PADD 1 South. 

b. Emissions From Motor Vehicles 

We use the EPA Predictive Models to 

estimate the impact of gasoline fuel 

quality on exhaust VOC and NOX

emissions from motor vehicles. These 

models were developed in 2000, in 

support of EPA’s response to 

California’s request for a waiver of the 

RFG oxygen mandate. These models 

represent a significant update of the 

EPA Complex Model. However, they are 

still based on emission data from Tier 0 

vehicles (roughly equivalent to 1990 

model year vehicles). We based our 

estimates of the impact of fuel quality 

on CO emissions on the EPA 

MOBILE6.2 model. We base our 

estimates of the impact of fuel quality 


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103The one exception was the impact of sulfur on 

emissions from these later vehicles, which is not an 

issue here due to the fact that renewable fuel use 

is not expected to change sulfur levels significantly. 

104An exception is that MOBILE6.2 applies the 

effect of oxygenate on CO emissions to Tier 1 and 

later vehicles which are expected to be high 

emitters based on their age and mileage. 

105For more information on California’s request 

for a waiver of the RFG oxygen mandate and the 

Decision Document for EPA’s response, see http:// 

www.epa.gov/otaq/rfg_regs.htm#waiver. 

on exhaust toxic emissions (benzene, 

formaldehyde, acetaldehyde, and 1,3- 

butadiene) primarily on the MOBILE6.2 

model, updated to reflect the effect of 

fuel quality on exhaust VOC emissions 

per the EPA Predictive Models. Very 

limited data are available on the effect 

of gasoline quality on PM emissions. 

Therefore, the effect of increased 

ethanol use on PM emissions can only 

be qualitatively discussed. 

In responding to California’s request 

for a waiver of the RFG oxygen mandate 

in 2000, we found that both very limited 

and conflicting data were available on 

the effect of fuel quality on exhaust 

emissions from Tier 1 and later 

vehicles.103 Thus, we assumed at the 

time that changes to gasoline quality 

would not affect VOC, CO and NOX

exhaust emissions from these 

vehicles.104 Very little additional data 

have been collected since that time on 

which to modify this assumption. 

Consequently, for our primary analysis 

for today’s final rule we have 

maintained the assumption that changes 

to gasoline do not affect exhaust 

emissions from Tier 1 and later 

technology vehicles. 

For the NPRM, we evaluated one 

recent study by the Coordinating 

Research Council (CRC) which assessed 

the impact of ethanol and two other fuel 

properties on emissions from twelve 

2000–2004 model year vehicles (CRC 

study E–67). Based on comments 

received on the NPRM, we evaluated 

four additional studies of the fuelemission effects of recent model year 

vehicles. The results of these test 

programs indicate that emissions from 

these late model year vehicles are likely 

sensitive to changes in fuel properties. 

However, both the size and direction of 

the effects are not consistent between 

the various studies. More testing is still 

needed before confident predictions of 

the effect of fuel quality on emissions 

from these vehicles can be made. 

In the NPRM, we developed two sets 

of assumptions regarding the effect of 

fuel quality on emissions from Tier 1 

and later vehicles to reflect this 

uncertainty. A primary analysis 

assumed that exhaust emissions from 

Tier 1 and later vehicles are not 

sensitive to fuel quality. This is 

consistent with our analysis of 

California’s request for a waiver of the 

RFG oxygen mandate. A sensitivity 

analysis assumed that the NMHC and 

NOX emissions from Tier 1 and later 

vehicles were as sensitive to fuel quality 

as Tier 0 vehicles. Only one effect of 

fuel quality on CO emissions was 

assumed, that contained in EPA’s 

MOBILE6.2 emission inventory model. 

The five available studies of Tier 1 

and later vehicles support continuing 

this approach for exhaust NMHC and 

NOX emissions. The assumptions 

supporting both our primary and 

sensitivity analyses reasonably bracket 

the results of the five studies. However, 

we have decided to perform a sensitivity 

analysis for CO emissions, as well. In 

this case, we apply the fuel-emission 

effects from MOBILE6.2 for Tier 0 

vehicles to Tier 1 and later vehicles. 

This is analogous to the approach taken 

for exhaust NMHC and NOX emissions. 

We base our estimates of fuel quality 

on non-exhaust VOC and benzene 

emissions on the EPA MOBILE6.2 

model. The one exception to this is the 

effect of ethanol on permeation 

emissions through plastic fuel tanks and 

elastomers used in fuel line 

connections. Recent testing has shown 

that ethanol increases permeation 

emissions, both by permeating itself and 

increasing the permeation of other 

gasoline components. This effect was 

included in EPA’s analysis of 

California’s most recent request for a 

waiver of the RFG oxygen requirement, 

but is not in MOBILE6.2.105 Therefore, 

we have added the effect of ethanol on 

permeation emissions to MOBILE6.2’s 

estimate of non-exhaust VOC emissions 

in assessing the impact of gasoline 

quality on these emissions. 

No models are available which 

address the impact of gasoline quality 

on PM emissions. Very limited data 

indicate that ethanol blending might 

reduce exhaust PM emissions under 

very cold weather conditions (e.g., 

¥20 °F to 0 °F). Very limited testing at 

warmer temperatures (e.g., 20 °F to 

75 °F) shows no definite trend in PM 

emissions with oxygen content. Thus, 

for now, no quantitative estimates can 

be made regarding the effect of ethanol 

use on direct PM emissions. 

Table VIII.A.1.b–1 presents the 

average per vehicle (2012 fleet) emission 

impacts of three types of RFG: Nonoxygenated, a typical MTBE RFG as has 

been marketed in the Gulf Coast, and a 

typical ethanol RFG which has been 

marketed in the Midwest. 

TABLE VIII.A.1.B–1.—EFFECT OF RFG ON PER MILE EMISSIONS FROM TIER 0 VEHICLES RELATIVE TO A TYPICAL 9PSI

RVP CONVENTIONAL GASOLINE a

Pollutant Source 

Non-Oxy 

RFG 

(percent) 

11 Volume 

percent 

MTBE 

10 Volume 

percent 

ethanol 

Exhaust Emissions 

VOC ...................................................................... EPA Predictive Models ......................................... ¥13.4 ¥15.3 ¥9.7 

NOX ...................................................................... ¥2.4 ¥1.7 7.3 

CO ......................................................................... MOBILE6.2 ........................................................... ¥22 ¥31 ¥36 

Exhaust Benzene .................................................. EPA Predictive and Complex Models .................. ¥21.2 ¥29.7 ¥38.9 

Formaldehyde ....................................................... ¥5.9 19.4 2.3 

Acetaldehyde ........................................................ ¥0.2 ¥9.5 173.7 

1,3-Butadiene ........................................................ 20.9 ¥29.2 6.1 

Non-Exhaust Emissions 

VOC ...................................................................... MOBILE6.2 & CRC E–65 ..................................... ¥30 ¥30 ¥18 

Benzene ................................................................ MOBILE6.2 & Complex Models ........................... ¥40 ¥43 ¥32 

aAverage per vehicle effects for the 2012 fleet during summer conditions. 


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As can be seen, all three types of RFG 

produce significantly lower emissions of 

VOC, CO and benzene than 

conventional gasoline. The impact of 

ethanol RFG on non-exhaust VOC 

emissions is lower than the other two 

types of RFG due to the impact of 

ethanol on permeation emissions. The 

impact of RFG on emissions of NOX and 

the other air toxics depends on the type 

of RFG blend. The most notable effect 

on toxic emissions in percentage terms 

is the 173 percent increase in 

acetaldehyde with the use of ethanol. 

However, as will be seen below, base 

acetaldehyde emissions are low relative 

to the other toxics. While not shown, 

the total mass emissions of the four 

toxic pollutants always decreases, as 

benzene is by far the largest constituent. 

It should be noted that these 

comparisons assume that all gasoline 

blends meet EPA’s Tier 2 gasoline sulfur 

standard of 30 ppm. Prior to the Tier 2 

program, RFG contained less sulfur than 

conventional gasoline and reduced NOX

emissions to a greater degree compared 

to conventional gasoline. 

Historically, no non-oxygenated RFG 

was sold, due to the requirement that 

RFG contain at least 2.0 weight percent 

oxygen. However, with the Energy Act’s 

removal of this requirement, all three 

types of RFG blends can be sold today. 

Increased use of ethanol in RFG would 

therefore either replace MTBE RFG or 

non-oxygenated RFG. The former has 

already occurred in many areas, as 

MTBE was essentially removed from the 

U.S. gasoline market by the end of 2006. 

The impact of using ethanol in RFG in 

lieu of MTBE or no oxygenate can be 

seen from comparing the relative 

impacts of the various RFG blends 

shown in Table VIII.A.1.b–1. 

Blending RFG with ethanol instead of 

MTBE or no oxygenate will increase 

VOC and NOX emissions and decrease 

CO emissions. Exhaust benzene and 

formaldehyde emissions will decrease, 

but non-exhaust benzene, acetaldehyde, 

and 1,3-butadiene emissions will 

increase. All of these impacts are on a 

per vehicle basis and apply to Tier 0 

vehicles only. The overall impact of 

increased ethanol use on total emissions 

of these various pollutants is described 

below. 

Table VIII.A.1.b–2 presents the effect 

of blending either MTBE or ethanol into 

conventional gasoline while matching 

octane. 

TABLE VIII.A.1.B–2.—EFFECT OF MTBE AND ETHANOL IN CONVENTIONAL GASOLINE ON TIER 0 VEHICLE EMISSIONS

RELATIVE TO A TYPICAL NON-OXYGENATED CONVENTIONAL GASOLINE a

Pollutant Source 

11 Volume 

percent 

MTBE 

10 Volume 

percent 

ethanol b

Exhaust VOC .................................................................... EPA Predictive Models .................................................... ¥9.2 ¥7.4 

NOX ................................................................................... ¥2.6 7.7 

CO c .................................................................................. MOBILE6.2 ....................................................................... ¥6/¥11 ¥11/¥19 

Exhaust Benzene .............................................................. EPA Predictive and Complex Models .............................. ¥22.8 ¥24.9 

Formaldehyde ................................................................... +21.3 +6.7 

Acetaldehyde .................................................................... +0.8 +156.8 

1,3-Butadiene .................................................................... ¥3.7 ¥13.2 

Non-Exhaust VOC ............................................................ MOBILE6.2 ....................................................................... Zero +30 

Non-Exhaust Benzene ...................................................... MOBILE6.2 & Complex Models ....................................... ¥9.5 +15.8 

aAverage per vehicle effects for the 2012 fleet during summer conditions. 

bAssumes a 1.0 psi RVP waiver for ethanol blends. 

cThe first figure shown applies to normal emitters; the second applies to high emitters. 

Use of either oxygenate reduces 

exhaust VOC and CO emissions, but 

increases NOX emissions. The ethanol 

blend increases non-exhaust VOC 

emissions due to the commonly granted 

1.0 psi waiver of the RVP standard, as 

well as increased permeation emissions. 

Both oxygenated blends reduce exhaust 

benzene and 1,3-butadiene emissions. 

As above, ethanol increases non-exhaust 

benzene and acetaldehyde emissions. 

While small amounts of MTBE may 

have still been used in CG in 2004, for 

our reference case we have assumed that 

all MTBE use was in RFG. Therefore, we 

are not predicting any emissions impact 

related to removing MTBE from 

conventional gasoline. Increased use of 

conventional ethanol blends will be in 

lieu of non-oxygenated conventional 

gasoline. Thus, the more relevant 

column in Table VII.A.1.b–2 for our 

modeling is the last column, which 

shows the emission impact of a 10 

volume percent ethanol blend relative to 

non-oxygenated gasoline. 

The exhaust emission effects shown 

above for VOC and NOX emissions only 

apply to Tier 0 vehicles in our primary 

analysis. For example, MOBILE6.2 

estimates that 34 of exhaust VOC 

emissions and 16 of NOX emissions 

from gasoline vehicles in 2012 come 

from Tier 0 vehicles. In the sensitivity 

analysis, these effects are extended to all 

gasoline vehicles. The effect of RVP and 

permeation on non-exhaust VOC 

emissions is temperature dependent. 

The figures shown above are based on 

the distribution of temperatures 

occurring across the U.S. in July. 

We received several comments related 

to the effect of ethanol on emissions 

from onroad vehicles. None of the 

comments led us to change the basic 

approach taken to estimating the impact 

of changing fuel quality described 

above. Several comments suggested that 

we expand our discussion of the 

uncertainty in these fuel effects (as well 

as the effects of fuel quality on 

emissions from nonroad equipment and 

diesels described below). While such an 

expanded discussion might be generally 

desirable, the lack of relevant emission 

data from late model vehicles and 

equipment prevents this. We believe 

that we have adequately described the 

uncertainty in the emission estimates 

presented below and our plans to obtain 

more data in order to improve these 

estimates in the near future. 

c. Nonroad Equipment 

To estimate the effect of gasoline 

quality on emissions from nonroad 

equipment, we used EPA’s NONROAD 

emission model. We used the 2005 

version of this model, NONROAD2005, 

which includes the effect of ethanol on 

permeation emissions from most 

nonroad equipment. 

Only sulfur and oxygen content affect 

exhaust VOC, CO and NOX emissions in 

NONROAD. Since sulfur level is 

assumed to remain constant, the only 

difference in exhaust emissions between 

conventional and reformulated gasoline 

is due to oxygen content. Table 

VIII.A.1.c–1 shows the effect of adding 


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106 71, Federal Register, 15804, March 29, 2006. 107 ‘‘A Comprehensive Analysis of Biodiesel 

Impacts on Exhaust Emissions,’’ Draft Technical 

Report, U.S. EPA, EPA420–P–02–001, October 

2002. http://www.epa.gov/otaq/models/biodsl.htm. 

11 volume percent MTBE or 10 volume percent ethanol to non-oxygenated 

gasoline on these emissions. 

TABLE VIII.A.1.C–1.—EFFECT MTBE AND ETHANOL ON NONROAD EXHAUST EMISSIONS RELATIVE TO A TYPICAL NONOXYGENATED GASOLINE

Base fuel 

4-Stroke engines 2-Stroke engines 

11 Volume 

percent 

MTBE 

10 Volume 

percent 

ethanol 

11 Volume 

percent 

MTBE 

10 Volume 

percent 

ethanol 

Exhaust VOC ................................................................................................................... ¥9 ¥16 ¥1 ¥2 

Non-Exhaust VOC ........................................................................................................... 0 26 0 26 

CO .................................................................................................................................... ¥13 ¥22 ¥13 ¥23 

NOX .................................................................................................................................. +23 +40 +37 +65 

As can be seen, higher oxygen content 

reduces exhaust VOC and CO emissions 

significantly, but also increases NOX

emissions. However, NOX emissions 

from these engines tend to be fairly low 

to start with, given the fact that these 

engines run much richer than 

stoichiometric. Thus, a large percentage 

increase of a relative low base value can 

be a relatively small increase in absolute 

terms. 

Evaporative emissions from nonroad 

equipment are impacted by only RVP, 

and permeation by ethanol content. 

Both the RVP increase due to blending 

of ethanol and its permeation effect 

cause non-exhaust VOC emissions to 

increase with the use of ethanol in 

nonroad equipment. The 26 percent 

effect represents the average impact 

across the U.S. in July for both 2-stroke 

and 4-stroke equipment. We updated 

the NONROAD2005 hose permeation 

emission factors for small spark-ignition 

engines and recreational marine 

watercraft to reflect the use of ethanol. 

For nonroad toxics emissions, we base 

our estimates of the impact of fuel 

quality on the fraction of exhaust VOC 

emissions represented by each toxic on 

MOBILE6.2 (i.e., the same effects 

predicted for onroad vehicles). The 

National Mobile Inventory Model 

(NMIM) contains estimates of the 

fraction of VOC emissions represented 

by the various air toxics based on 

oxygenate type (none, MTBE or 

ethanol). However, estimates for 

nonroad gasoline engines running on 

different fuel types are limited, making 

it difficult to accurately model the 

impacts of changes in fuel quality. In 

the recent final rule addressing mobile 

air toxic emissions, EPA replaced the 

toxic-related fuel effects contained in 

NMIM with those from MOBILE6.2 for 

onroad vehicles.106 We follow the same 

methodology here. Future testing could 

significantly alter these emission impact 

estimates. 

2. Diesel Fuel Quality: Biodiesel 

EPA assessed the impact of biodiesel 

fuel on emissions in 2002 and published 

a draft report summarizing the 

results.107 This report included a 

technical analysis of biodiesel effects on 

regulated and unregulated pollutants 

from diesel powered vehicles and 

concluded that biodiesel fuels improved 

PM, HC and CO emissions of diesel 

engines while slightly increasing their 

NOX emissions. 

While the conclusions reached in the 

2002 EPA report relative to biodiesel 

effects on VOC, CO and PM emissions 

have been generally accepted, the 

magnitude of the B20 effect on NOX

remains controversial due to conflicting 

results from different studies. 

Significant new testing is being planned 

with broad stakeholder participation 

and support in order to better estimate 

the impact of biodiesel on NOX and 

other exhaust emissions from the in-use 

fleet of diesel engines. We hope to 

incorporate the data from such 

additional testing into the analyses for 

other studies required by the Energy Act 

in 2008 and 2009, and into a subsequent 

rule to set the RFS program standard for 

2013 and later. 

3. Renewable Fuel Production and 

Distribution 

Areas experiencing increased 

renewable production will experience 

the corresponding emission increases 

associated with their production. The 

primary impact of renewable fuel 

production and distribution regards 

ethanol, since it is expected to be the 

predominant renewable fuel used in the 

foreseeable future. We approximate the 

impact of increased ethanol and 

biodiesel production, including corn 

and soy farming, on emissions based on 

DOE’s GREET model, version 1.7. In 

addition, we develop a second estimate 

of emissions from ethanol production 

facilities using estimates of emissions 

from current ethanol plants obtained 

from the States. We also include 

emissions effects resulting from the 

transport of increased volumes of 

renewable fuels and decreased volumes 

of gasoline and diesel fuel. These 

emissions are summarized in Table 

VIII.A.3–1. 

TABLE VIII.A.3–1.—WELL-TO-PUMP EMISSIONS FOR PRODUCING AND DISTRIBUTING RENEWABLE FUELS

[Grams per gallon ethanol or biodiesel] a

Pollutant 

GREET1.7 GREET1.7 + state data 

Biodiesel— 

Current eth- GREET1.7 

anol plants 

Future ethanol plants Current ethanol plants Future ethanol plants 

VOC ......................................................................................................... 1.8 1.8 3.6 3.2 37.6 

CO ............................................................................................................ 4.0 4.1 4.4 4.3 12.7 

NOX .......................................................................................................... 11.4 11.4 10.8 13.0 25.1 

PM10 ........................................................................................................ 4.9 4.9 6.1 2.8 4.8


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108These emission estimates do not include the 

impact of the recent mobile source air toxic 

standards (72 FR 8428, February 26, 2007). 

TABLE VIII.A.3–1.—WELL-TO-PUMP EMISSIONS FOR PRODUCING AND DISTRIBUTING RENEWABLE FUELS—Continued 

[Grams per gallon ethanol or biodiesel] a

Pollutant 

GREET1.7 GREET1.7 + state data 

Biodiesel— 

Current eth- GREET1.7 

anol plants 

Future ethanol plants Current ethanol plants Future ethanol plants 

SOX .......................................................................................................... 6.4 6.4 7.2 9.7 21.8 

a Includes credit for reduced distribution of gasoline and diesel fuel. 

At the same time, areas with refineries 

might experience reduced emissions, 

not necessarily relative to current 

emission levels, but relative to those 

which would have occurred in the 

future had renewable fuel use not risen. 

However, to the degree that increased 

renewable fuel use reduces imports of 

gasoline and diesel fuel, as opposed to 

the domestic production of these fuels, 

these reduced refinery emissions will 

occur overseas and not in the U.S. 

Similarly, areas with MTBE 

production facilities might experience 

reduced emissions from these plants as 

they cease producing MTBE. However, 

many of these plants may be converted 

to produce other gasoline blendstocks, 

such as iso-octane or alkylate. In this 

case, their emissions are not likely to 

change substantially. 

B. Impact on Emission Inventories 

We use the NMIM to estimate 

emissions under the various ethanol 

scenarios on a county by county basis. 

NMIM basically runs MOBILE6.2 and 

NONROAD2005 with county-specific 

inputs pertaining to fuel quality, 

ambient conditions, levels of onroad 

vehicle VMT and nonroad equipment 

usage, etc. We ran NMIM for two 

months, July and January. We estimate 

annual emission inventories by 

summing the two monthly inventories 

and multiplying by six. 

As described above, we removed the 

effect of gasoline fuel quality on exhaust 

VOC and NOX emissions from the 

onroad motor vehicle inventories which 

are embedded in MOBILE6.2. We then 

applied the exhaust emission effects 

from the EPA Predictive Models. In our 

primary analysis, we only applied these 

EPA Predictive Model effects to exhaust 

VOC and NOX emissions from Tier 0 

vehicles. In a sensitivity case, we 

applied them to exhaust VOC and NOX

emissions from all vehicles. Regarding 

the effect of fuel quality on emissions of 

four air toxics from nonroad equipment 

(in terms of their fraction of VOC 

emissions), in all cases we replaced the 

fuel effects contained in NMIM with 

those for motor vehicles contained in 

MOBILE6.2. The projected emission 

inventories for the primary analysis are 

presented first, followed by those for the 

sensitivity analysis. 

1. Primary Analysis 

The national emission inventories for 

VOC, CO and NOX in 2012 with current 

fuels (i.e., ‘‘reference fuel’’) are 

summarized in Table VIII.B.1–1. Also 

shown are the changes in emissions 

projected for the two levels of ethanol 

use (i.e., ‘‘control cases’’) described in 

Section VI. 

TABLE VIII.B.1–1.—2012 EMISSIONS NATIONWIDE FROM GASOLINE VEHICLES AND EQUIPMENT UNDER SEVERAL ETHANOL

USE SCENARIOS—PRIMARY ANALYSIS

[Tons per year] 108

Pollutant 

Inventory Change in inventory in 

control cases 

Reference 

case RFS case EIA case 

VOC ......................................................................................................................................................... 5,882,000 18,000 43,000 

NOX .......................................................................................................................................................... 2,487,000 23,000 40,000 

CO ............................................................................................................................................................ 55,022,000 ¥483,000 ¥1,366,000 

Benzene ................................................................................................................................................... 178,000 ¥3,200 ¥7,200 

Formaldehyde .......................................................................................................................................... 40,400 ¥600 ¥200 

Acetaldehyde ........................................................................................................................................... 19,900 3,400 7,100 

1,3-Butadiene ........................................................................................................................................... 18,900 ¥200 ¥300 

Both VOC and NOX emissions are 

projected to increase with increased use 

of ethanol. However, the increases are 

small, generally less than 2 percent. CO 

emissions are projected to decrease by 

about 0.9 to 2.5 percent. Benzene 

emissions are projected to decrease by 

1.8 to 4.0 percent. Formaldehyde 

emissions are projected to decrease 

slightly, on the order of 0.5 to 1.5 

percent. 1,3-butadiene emissions are 

projected to decrease by about 1.1 to 1.6 

percent. The largest change is in 

acetaldehyde emissions, an increase of 

17.1 to 35.7 percent, as acetaldehyde is 

a partial combustion product of ethanol. 

CO also participates in forming ozone, 

much like VOCs. Generally, CO is 15– 

50 times less reactive than typical VOC. 

Still, the reduction in CO emissions is 

roughly 27–32 times the increase in 

VOC emissions in the two scenarios. 

Thus, the projected reduction in CO 

emissions is important from an ozone 

perspective. However, as described 

above, the methodology for projecting 

the effect of ethanol use on CO 

emissions is inconsistent with that for 

exhaust VOC and NOX emissions. Thus, 

comparisons between changes in VOC 

and CO emissions are particularly 

uncertain. 

There will also be some increases in 

emissions due to ethanol and biodiesel 

production. Table VIII.B.1–2 shows 

estimates of annual emissions expected 

to occur nationwide due to increased 

production of ethanol. These estimates 

include a reduction in emissions related 

to the distribution of the displaced 

gasoline. The table reflects the use of 


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emissions factors from DOE’s GREET 

model, version 1.7, as well as estimates 

of ethanol plant emissions obtained 

from the States. It should be noted that 

emissions in the base case assume an 

80/20 mix of dry mill and wet mill 

facilities. New plants (and thus, the 

emission increases) assume 100% dry 

mill facilities. 

TABLE VIII.B.1–2.—ANNUAL EMISSIONS NATIONWIDE FROM ETHANOL PRODUCTION AND TRANSPORTATION: 2012 

[Tons per year] 

GREET1.7 GREET1.7 + State data 

Base case RFS case EIA case Base case RFS case EIA case 

Emissions Increase in emissions Emissions Increase in emissions 

VOC ................................................................................. 8,000 5,000 11,000 14,000 10,000 20,000 

NOX .................................................................................. 17,000 13,000 26,000 18,000 14,000 27,000 

CO .................................................................................... 49,000 35,000 72,000 56,000 40,000 81,000

PM10 ................................................................................. 21,000 15,000 30,000 12,000 9,000 18,000 

SOX .................................................................................. 27,000 20,000 41,000 42,000 30,000 61,000 

As can be seen, the potential increases 

in emissions from ethanol production 

and transportation are of the same order 

of magnitude as those from ethanol use, 

with the exception of CO emissions. The 

vast majority of these emissions are 

related to farming and ethanol 

production. Both farms and ethanol 

plants are generally located in ozone 

attainment areas. 

Where counties are constructing new 

ethanol plants, expanding existing 

plants, or planning construction for 

future plants, the average increase in 

VOC and NOX emissions from plants 

alone are about 26 tons/month VOC and 

35 tons/month NOX using state data 

(about 17 tons/month VOC and 25 tons/ 

month NOX using GREET 1.7 emission 

factors). Average VOC and NOX

emissions increase to about 61 tons/ 

month and 83 tons/month, respectively, 

in the 10% of counties expecting largest 

increases in ethanol production. For 

both VOC and NOX, emissions estimates 

are about 35% less when using the 

GREET 1.7 emission factors. 

Table VIII.B.1–3 shows estimates of 

annual emissions expected to occur 

nationwide due to increased production 

of biodiesel. These estimates include a 

reduction in emissions related to the 

distribution of the displaced diesel fuel. 

Again, these emissions are generally 

expected to be in ozone attainment 

areas. 

TABLE VIII.B.1–3.—ANNUAL EMISSIONS NATIONWIDE FROM BIODIESEL

PRODUCTION AND TRANSPORTATION

[Tons per year] 

Pollutant 

Reference 

inventory: 

30 mill gal 

biodiesel 

per year 

2012 Emissions inventory: 300 

mill gal 

biodiesel 

per year 

VOC .................. 1,400 14,000 

NOX .................. 1,500 15,000 

CO .................... 800 8,000 

TABLE VIII.B.1–3.—ANNUAL EMISSIONS NATIONWIDE FROM BIODIESEL

PRODUCTION AND

TRANSPORTATION—Continued 

[Tons per year] 

Pollutant 

Reference 

inventory: 

30 mill gal 

biodiesel 

per year 

2012 Emissions inventory: 300 

mill gal 

biodiesel 

per year 

PM10 .................. 50 500 

SOX ................... 250 2,500 

2. Sensitivity Analysis 

The national emission inventories for 

VOC and NOX in 2012 with current 

fuels are summarized in Table VIII.B.2– 

1. Here, the emission effects contained 

in the EPA Predictive Models are 

assumed to apply to all vehicles, not 

just Tier 0 vehicles. Also shown are the 

changes in emissions projected for the 

two cases for future ethanol volume. 

TABLE VIII.B.2–1.—2012 EMISSIONS NATIONWIDE FROM GASOLINE VEHICLES AND EQUIPMENT UNDER TWO FUTURE

ETHANOL USE SCENARIOS—SENSITIVITY ANALYSIS

[Tons per year] 

Pollutant 

Inventory Change in inventory in 

control cases 

Reference 

case RFS case EIA case 

VOC ......................................................................................................................................................... 5,834,000 ¥20,000 ¥4,000 

NOX .......................................................................................................................................................... 2,519,000 68,000 106,000 

CO ............................................................................................................................................................ 54,315,000 ¥692,000 ¥1,975,000 

Benzene ................................................................................................................................................... 175,700 ¥5,000 ¥9,400 

Formaldehyde .......................................................................................................................................... 39,600 ¥1,100 ¥700 

Acetaldehyde ........................................................................................................................................... 19,500 3,000 6,600 

1,3-Butadiene ........................................................................................................................................... 18,600 ¥400 ¥600 

The overall VOC and NOX emission 

impacts of the various ethanol use 

scenarios change to some degree when 

all motor vehicles are assumed to be 

sensitive to fuel ethanol content. The 

increase in VOC emissions turns into a 

net decrease due to a greater reduction 

in exhaust VOC emissions from onroad 

vehicles. However, the increase in NOX

emissions gets larger, as more vehicles 

are assumed to be affected by ethanol. 

Emissions of the four air toxics 

generally decrease slightly, due to the 

greater reduction in exhaust VOC 

emissions. 


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3. Local and Regional VOC and NOX

Emission Impacts in July 

We also estimate the percentage 

change in VOC, NOX, and CO emissions 

from gasoline fueled motor vehicles and 

equipment in those areas which actually 

experienced a significant change in 

ethanol use. Specifically, we focused on 

areas where the market share of ethanol 

blends was projected to change by 50 

percent or more. We also focused on 

summertime emissions, as these are 

most relevant to ozone formation. 

Finally, we developed separately 

estimates for: (1) RFG areas, including 

the state of California and the portions 

of Arizona where their CBG fuel 

programs apply, (2) low RVP areas (i.e., 

RVP standards less than 9.0 RVP, and 

(3) areas with a 9.0 RVP standard. This 

set of groupings helps to highlight the 

emissions impact of increased ethanol 

use in those areas where emission 

control is most important. 

Table VIII.B.3–1 presents our primary 

estimates of the percentage change in 

VOC, NOX, and CO emission inventories 

for these three types of areas. Note that 

the analyses here are very similar to 

those described in Section 5.1 of the 

RIA, with the exception that Table 

VIII.B.3–1 below reflects 50 states 

(instead of 37 eastern states) and 

excludes diesel emissions. 

TABLE VIII.B.3–1.—JULY 2015 CHANGE IN EMISSIONS FROM GASOLINE VEHICLES AND EQUIPMENT IN COUNTIES WHERE

ETHANOL USE CHANGED SIGNIFICANTLY—PRIMARY ANALYSIS

Ethanol use RFS case EIA case 

RFG Areas 

Ethanol Use ....................................................... Down ................................................................ Up. 

VOC ................................................................... 0.8% ................................................................. 2.3%. 

NOX ................................................................... ¥3.4% .............................................................. 1.6%. 

CO ..................................................................... 6.1% ................................................................. ¥2.6%. 

Low RVP Areas 

Ethanol Use ....................................................... Up ..................................................................... Up. 

VOC ................................................................... 4.2% ................................................................. 4.6%. 

NOX ................................................................... 6.2% ................................................................. 5.7%. 

CO ..................................................................... ¥12.5% ............................................................ ¥13.7%. 

Other Areas (9.0 RVP) 

Ethanol Use ....................................................... Up ..................................................................... Up. 

VOC ................................................................... 3.6% ................................................................. 4.6%. 

NOX ................................................................... 7.3% ................................................................. 7.0%. 

CO ..................................................................... ¥6.4% .............................................................. ¥6.0%. 

As expected, increased ethanol use 

tends to increase NOX emissions. The 

increase in low RVP and other areas is 

greater than in RFG areas, since the RFG 

in the RFG areas included in this 

analysis all contained MTBE. Also, 

increased ethanol use tends to increase 

VOC emissions, indicating that the 

increase in non-exhaust VOC emissions 

exceeds the reduction in exhaust VOC 

emissions. This effect is muted with 

RFG due to the absence of an RVP 

waiver for ethanol blends. We would 

expect very similar results for 2012. The 

reader is referred to Chapter 2 of the RIA 

for discussion of how ethanol levels will 

change at the state-level. 

Table VIII.B.3–2 presents the 

percentage change in VOC, NOX, and 

CO emission inventories under our 

sensitivity case (i.e., when we apply the 

emission effects of the EPA Predictive 

Models to all motor vehicles). 

TABLE VIII.B.3–2.—JULY 2015 CHANGE IN EMISSIONS FROM GASOLINE VEHICLES AND EQUIPMENT IN COUNTIES WHERE

ETHANOL USE CHANGED SIGNIFICANTLY—SENSITIVITY ANALYSIS

Ethanol use RFS case EIA case 

RFG Areas 

Ethanol Use ....................................................... Down ................................................................ Up. 

VOC ................................................................... ¥1.0% .............................................................. 1.0%. 

NOX ................................................................... ¥0.9% .............................................................. 5.6%. 

CO ..................................................................... 7.3% ................................................................. ¥3.0%. 

Low RVP Areas 

Ethanol Use ....................................................... Up ..................................................................... Up. 

VOC ................................................................... 3.4% ................................................................. 3.7%. 

NOX ................................................................... 10.4% ............................................................... 10.8%. 

CO ..................................................................... ¥15.0% ............................................................ ¥16.4%. 

Other Areas (9.0 RVP) 

Ethanol Use ....................................................... Up ..................................................................... Up. 

VOC ................................................................... 3.0% ................................................................. 3.9%. 

NOX ................................................................... 10.8% ............................................................... 11.0%. 


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TABLE VIII.B.3–2.—JULY 2015 CHANGE IN EMISSIONS FROM GASOLINE VEHICLES AND EQUIPMENT IN COUNTIES WHERE

ETHANOL USE CHANGED SIGNIFICANTLY—SENSITIVITY ANALYSIS—Continued 

Ethanol use RFS case EIA case 

CO ..................................................................... ¥9.0% .............................................................. ¥8.9%. 

Directionally, the changes in VOC and 

NOX emissions in the various areas are 

consistent with those from our primary 

analysis. The main difference is that the 

increases in VOC emissions are smaller, 

due to more vehicles experiencing a 

reduction in exhaust VOC emissions, 

and the increases in NOX emissions are 

larger. 

C. Impact on Air Quality 

We estimate the impact of increased 

ethanol use on the ambient 

concentrations of two pollutants: Ozone 

and PM. Quantitative estimates are 

made for ozone, while only qualitative 

estimates can be made currently for 

ambient PM. These impacts are 

described below. 

1. Impact of Increased Ethanol Use on 

Ozone 

We use a metamodeling tool 

developed at EPA, the ozone response 

surface metamodel (Ozone RSM), to 

estimate the effects of the projected 

changes in emissions from gasoline 

vehicles and equipment for the RFS and 

EIA cases. We included the estimated 

changes in emissions from renewable 

fuel production and distribution. 

Because of limitations in the Ozone 

RSM, we could not easily assign these 

emissions to the specific counties where 

the plants are or are expected to be 

located. Instead, we assigned all of the 

emissions related to renewable fuel 

production and distribution to the set of 

states expected to contain most of the 

production facilities. 

The Ozone RSM was created using 

multiple runs of the Comprehensive Air 

Quality Model with Extensions (CAMX). 

Base and proposed control CAMX

metamodeling was completed for the 

year 2015 over a modeling domain that 

includes all or part of 37 Eastern U.S. 

states, plus the District of Columbia. For 

more information on the Ozone RSM, 

please see Chapter 5 of the RIA for this 

final rule. 

The Ozone RSM limits the number of 

geographically distinct changes in VOC 

and NOX emissions which can be 

simulated. As a result, we could not 

apply distinct changes in emissions for 

each county. Therefore, two separate 

runs were made with different VOC and 

NOX emissions reductions. We then 

selected the ozone impacts from the 

various runs which best matched the 

VOC and NOX emission reductions for 

that county. This models the impact of 

local emissions reasonably well, but 

loses some accuracy with respect to 

ozone transport. No ozone impact was 

assumed for areas which did not 

experience a significant change in 

ethanol use. The predicted ozone 

impacts of increased ethanol use for 

those areas where ethanol use is 

projected to change by more than a 50% 

market share are summarized in Table 

VIII.C.1–1. As shown in the Table 5.1– 

2 of the RIA, national average impacts 

(based on the 37-state area modeled) 

which include those areas where no 

change in ethanol use is occurring are 

considerably smaller. 

TABLE VIII.C.1–1.—IMPACT ON 8-HOUR DESIGN VALUE EQUIVALENT OZONE LEVELS (PPB) a

Primary analysis Sensitivity analysis 

RFS case EIA case RFS case EIA case 

Minimum Change ............................................................................................................. ¥0.015 0.000 ¥0.115 0.028 

Maximum Change ............................................................................................................ 0.329 0.337 0.624 0.549 

Average Change b ............................................................................................................ 0.153 0.181 0.300 0.325 

Population-Weighted Change b ........................................................................................ 0.154 0.183 0.272 0.315 

a In comparison to the 80 ppb 8-hour ozone standards. 

bOnly for those areas experiencing a change in ethanol blend market share of at least 50 percent. 

As can be seen, ozone levels generally 

increase to a small degree with 

increased ethanol use. This is likely due 

to the projected increases in both VOC 

and NOX emissions. Some areas do see 

a small decrease in ozone levels. In our 

primary analysis, where exhaust 

emissions from Tier 1 and later onroad 

vehicles are assumed to be unaffected 

by ethanol use, the population-weighted 

increase in ambient ozone levels in 

those areas where ethanol use changed 

significantly is 0.154–0.183 ppb. Since 

the 8-hour ambient ozone standard is 85 

ppb, this increase represents about 0.2 

percent of the standard, a very small 

percentage. 

In our sensitivity analysis, where 

exhaust emissions from Tier 1 and later 

onroad vehicles are assumed to respond 

to ethanol like Tier 0 vehicles, the 

population-weighted increase in 

ambient ozone levels is slightly less 

than twice as high, or 0.272–0.315 ppb. 

This increase represents about 0.35 

percent of the standard. 

There are a number of important 

caveats concerning these estimates. 

First, the emission effects of adding 

ethanol to gasoline are based on 

extremely limited data for recent 

vehicles and equipment. Second, the 

Ozone RSM does not account for 

changes in CO emissions. As shown 

above, ethanol use should reduce CO 

emissions significantly, directionally 

reducing ambient ozone levels in those 

areas where ozone formation is VOClimited. (Ozone levels in areas which 

are NOX-limited are less likely to be 

affected by a change in CO emissions.) 

The Ozone RSM also does not account 

for changes in VOC reactivity. With 

additional ethanol use, the ethanol 

content of VOC should increase. Ethanol 

is less reactive than the average VOC. 

Therefore, this change should also 

reduce ambient ozone levels in a way 

not addressed by the Ozone RSM, again 

in those areas where ozone formation is 

predominantly VOC-limited. Because of 

these limitations, anyone interested in 

the impact of increased ethanol use on 

ozone in any particular area should 

utilize more comprehensive dispersion 

modeling which accounts for these and 

other important factors. 

We received several requests in 

comments on the proposal to quantify 

the impact of the reduced CO emissions 


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and VOC reactivity on ozone. As 

discussed in the S&A document, this is 

not possible without running more 

sophisticated ambient dispersion 

models. The impact of CO emissions 

and VOC reactivity on ozone vary 

significantly depending on ambient 

conditions and the relative amount of 

VOC and NOX in the atmosphere. 

Therefore, general rules of thumb 

cannot be applied. 

Moving to health effects, exposure to 

ozone has been linked to lung function 

decrements, respiratory symptoms, 

aggravation of asthma, increased 

hospital and emergency room visits, 

increased asthma medication usage, 

inflammation of the lungs, and a variety 

of other respiratory effects and 

cardiovascular effects including 

premature mortality. Ozone can also 

adversely affect the agricultural and 

forestry sectors by decreasing yields of 

crops and forests. Although the health 

and welfare impacts of changes in 

ambient ozone levels are typically 

quantified in regulatory impact 

analyses, we do not evaluate them for 

this analysis. On average, the changes in 

ambient ozone levels shown above are 

small and would be even smaller if 

changes in CO emissions and VOC 

reactivity were taken into account. The 

increase in ozone would likely lead to 

negligible monetized impacts. We 

therefore do not estimate and monetize 

ozone health impacts for the changes in 

renewable use due to the small 

magnitude of this change, and the 

uncertainty present in the air quality 

modeling conducted here, as well as the 

uncertainty in the underlying emission 

effects themselves discussed earlier. 

2. Particulate Matter 

Ambient PM can come from two 

distinct sources. First, PM can be 

directly emitted into the atmosphere. 

Second, PM can be formed in the 

atmosphere from gaseous pollutants. 

Gasoline-fueled vehicles and equipment 

contribute to ambient PM 

concentrations in both ways. 

As described above, we are not 

currently able to predict the impact of 

fuel quality on direct PM emissions 

from gasoline-fueled vehicles or 

equipment. Therefore, we are unable at 

this time to project the effect that 

increased ethanol use will have on 

levels of directly emitted PM in the 

atmosphere. 

PM can also be formed in the 

atmosphere (termed secondary PM here) 

from several gaseous pollutants emitted 

by gasoline-fueled vehicles and 

equipment. Sulfur dioxide emissions 

contribute to ambient sulfate PM. NOX

emissions contribute to ambient nitrate 

PM. VOC emissions contribute to 

ambient organic PM. Increased ethanol 

use is not expected to change gasoline 

sulfur levels, so emissions of sulfur 

dioxide and any resultant ambient 

concentrations of sulfate PM are not 

expected to change. Increased ethanol 

use is expected to increase NOX

emissions, so the possibility exists that 

ambient nitrate PM levels could 

increase. Increased ethanol is generally 

expected to increase total VOC 

emissions, which could also impact the 

formation of secondary organic PM. 

However, while non-exhaust VOC 

emissions are expected to increase, 

exhaust VOC emissions are expected to 

decrease. Generally, the higher the 

molecular weight of the specific VOC 

emitted, the greater the likelihood it will 

form PM in the atmosphere. Nonexhaust VOC is predominantly low in 

molecular weight, as much of it is due 

to fuel evaporating. Thus, emissions of 

VOCs likely to form PM in the 

atmosphere are likely decreasing with 

ethanol use. 

The formation of secondary organic 

PM is very complex, due in part to the 

wide variety of VOCs emitted into the 

atmosphere. The degree to which a 

specific gaseous VOC reacts to form PM 

in the atmosphere depends on the types 

of reactions that specific VOC undergoes 

and the products of those reactions. 

Both of these factors depend on other 

pollutants present, such as the hydroxyl 

radical, ozone, NOX and other reactive 

compounds. The relative mass of 

secondary PM formed per mass of 

gaseous VOC emitted can also depend 

on the total concentration of gaseous 

VOC and organic PM in the atmosphere. 

Most of the secondary organic PM exists 

in a continually changing equilibrium 

between the gaseous and PM phases. 

Both the rates of these reactions and the 

gaseous-PM equilibria depend on 

temperature, so seasonal differences can 

be expected. 

Recent smog chamber studies have 

indicated that gaseous aromatic VOCs 

can form secondary PM under certain 

conditions. These compounds comprise 

a greater fraction of exhaust VOC 

emissions than non-exhaust VOC 

emissions, as non-exhaust VOC 

emissions are dominated by VOCs with 

relatively high vapor pressures. 

Aromatic VOCs tend to have lower 

vapor pressures. As increased ethanol 

use is expected to reduce exhaust VOC 

emissions, emissions of aromatic VOCs 

should also decrease. In addition, 

refiners are expected to reduce the 

aromatic content of gasoline by 5 

volume percentage points as ethanol is 

blended into gasoline. Emissions of 

aromatic VOCs should decrease with 

lower concentrations of aromatics in 

gasoline. Thus, emissions of gaseous 

aromatic VOCs could decrease for both 

reasons. 

Overall, we expect that the decrease 

in secondary organic PM is likely to 

exceed the increase in secondary nitrate 

PM. In 1999, NOX emissions from 

gasoline-fueled vehicles and equipment 

comprised about 20% of national NOX

emissions from all sources. In contrast, 

gasoline-fueled vehicles and equipment 

comprised over 60% of all national 

gaseous aromatic VOC emissions. The 

percentage increase in national NOX

emissions due to increased ethanol use 

should be smaller than the percentage 

decrease in national emissions of 

gaseous aromatics. Finally, in most 

urban areas, ambient levels of secondary 

organic PM exceed those of secondary 

nitrate PM. Thus, directionally, we 

expect a net reduction in ambient PM 

levels due to increased ethanol use. 

However, we are unable to quantify this 

reduction at this time. 

EPA currently utilizes the CMAQ 

model to predict ambient levels of PM 

as a function of gaseous and PM 

emissions. This model includes 

mechanisms to predict the formation of 

nitrate PM from NOX emissions. 

However, it does not currently include 

any mechanisms addressing the 

formation of secondary organic PM. EPA 

is currently developing a model of 

secondary organic PM from gaseous 

toluene emissions. We plan to 

incorporate this mechanism into the 

CMAQ model in 2007. The impact of 

other aromatic compounds will be 

added as further research clarifies their 

role in secondary organic PM formation. 

Therefore, we expect to be able to 

quantitatively estimate the impact of 

decreased toluene emissions and 

increased NOX emissions due to 

increased ethanol use as part of future 

analyses of U.S. fuel requirements 

required by the Act. 

IX. Impacts on Fossil Fuel Consumption 

and Related Implications 

Renewable fuels have been of 

significant interest for many years due 

to their potential to displace fossil fuels, 

which have often been targeted as 

primary contributors to emissions of 

greenhouse gases such as carbon 

dioxide, and national energy concerns 

primarily due to an increasing 

dependence on foreign sources of 

petroleum. In the Notice of Proposed 

Rulemaking, we provided a preliminary 

assessment of the greenhouse gas 

emission and energy impacts of 

renewable fuel and an initial assessment 

of the economic value of renewable fuel 

displacing petroleum-based fuels. We 


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109 Greenhouse gases, Regulated Emissions, and 

Energy use in Transportation. 

also indicated that we would be 

updating an analysis of energy security 

impacts that had been prepared by 

analysts at the Oak Ridge National 

Laboratory (ORNL) of the Department of 

Energy. We present some discussion of 

that analysis here. 

We also performed a full lifecycle or 

well-to-wheel analysis for this final rule 

to estimate the GHG and fossil energy 

reductions from replacing petroleum 

based fuels with renewable fuels. 

Argonne National Laboratory’s (ANL) 

GREET109 model was utilized for this 

lifecycle analysis. Table IX–1 

summarizes this model’s estimated 

impact that increases in the use of 

renewable fuels are projected to have on 

GHG emissions and fossil fuel 

consumption for the two renewable fuel 

volume scenarios considered in this 

final rulemaking relative to the 

reference case. As described later in this 

section, the results in Table IX–1 are 

based on a number of input assumptions 

including coal being used as process 

fuel in 14% of ethanol facilities. 

As noted in Section III, although we 

have chosen to base our lifecycle 

analyses on Argonne National 

Laboratory’s GREET model there are a 

variety of other lifecycle models and 

analyses available. The choice of model 

inputs and assumptions all have a 

bearing on the results of lifecycle 

analyses, and many of these 

assumptions remain the subject of 

debate among researchers. Lifecycle 

analyses must also contend with the fact 

that the inputs and assumptions 

generally represent industry-wide 

averages even though energy consumed 

and emissions generated can vary 

widely from one facility or process to 

another. 

There currently exists no organized, 

comprehensive dialogue among 

stakeholders about the appropriate tools 

and assumptions behind any lifecycle 

analyses. We will be initiating more 

comprehensive discussions about 

lifecycle analyses with stakeholders in 

the near future. 

TABLE IX–1.—GREET MODEL LIFECYCLE REDUCTIONS FROM INCREASED RENEWABLE FUEL USE RELATIVE TO THE 2012 

REFERENCE CASE

RFS case EIA case 

Reduction % of trans. 

sector Reduction % of trans. sector 

Fossil Energy (QBtu) ................................................................................................... 0 .15 0.48 0 .27 0.85 

Petroleum Energy (Bgal) ............................................................................................. 2 .0 0.82 3 .9 1.60 

GHG Emissions (MMT CO2-eq.) ................................................................................. 8 .0 0.36 13 .1 0.59 

CO2 Emissions (MMT CO2) ........................................................................................ 11 .0 0.52 19 .5 0.93 

We used the petroleum energy 

reductions shown in Table IX–1 to 

determine implications on imports of 

petroleum products. Our analysis found 

that calculated petroleum energy 

reductions come almost entirely from 

imports of finished products in this 

2012 case and amount to the equivalent 

of 123,000 barrels of transportation fuel 

under the RFS case and 240,000 barrels 

of transportation fuel for the EIA case. 

Another effect of increased use of 

renewable fuels in the U.S. is that it 

diversifies the energy sources in making 

transportation fuel. Diverse sources of 

fuel energy reduce both financial and 

strategic risks associated with a 

potential disruption in supply or a spike 

in cost of a particular energy source. 

This reduction in risks is a measure of 

improved energy security. The ORNL 

report used an ‘‘oil premium’’ approach 

to identify those energy-security related 

impacts which are not reflected in the 

market price of oil, and which are 

expected to change in response to an 

incremental change in the level of U.S. 

oil imports. 

The following sections provide a more 

complete description of our analyses of 

the GHG emissions, fossil fuel, oil 

imports, and energy security impacts of 

this final rule. 

A. Impacts on Lifecycle GHG Emissions 

and Fossil Energy Use 

Although the use of renewable fuels 

in the transportation sector directly 

displaces some petroleum consumed as 

motor vehicle fuel, this displacement of 

petroleum is in fact only one aspect of 

the overall impact of renewable fuels on 

fossil fuel use. Fossil fuels are also used 

in producing and transporting 

renewable feedstocks such as plants or 

animal byproducts, in converting the 

renewable feedstocks into renewable 

fuel, and in transporting and blending 

the renewable fuels for consumption as 

motor vehicle fuel. To estimate the true 

impacts of increases in renewable fuels 

on fossil fuel use, modelers attempt to 

take many or all these steps into 

account. 

Similarly, energy is used and GHGs 

emitted in the pumping of oil, 

transporting the oil to the refinery, 

refining the crude oil into finished 

transportation fuel, transporting the 

refined gasoline or diesel fuel to the 

consumer and then burning the fuel in 

the vehicle. Such analyses are termed 

lifecycle or well-to-wheels analyses. We 

performed a full lifecycle analysis as 

part of this final rulemaking to 

determine the GHG and fossil energy 

reductions from the increased use of 

renewable fuels. 

This lifecycle assessment approach 

and rationale were highlighted in the 

proposal. Comments received focused 

mainly on improving the process, for 

example the choice of lifecycle model 

used and initiating a stakeholder 

dialogue to build consensus around the 

assumptions and approach. In general 

comments were supportive of using a 

full lifecycle assessment approach, but 

differed on the appropriate model and 

associated assumptions EPA should use 

in its analysis. 

1. Time Frame and Volumes Considered 

The results presented in this analysis 

represent a snapshot in time. They 

represent annual GHG and fossil fuel 

savings in the year considered, in this 

case 2012. Consistent with the 

emissions modeling described in 

Section VII, our analysis of the GHG and 

fossil fuel consumption impacts of 

renewable fuel use was conducted using 

three volume scenarios. The first 

scenario was the same reference case 

used elsewhere in this final rulemaking. 

The reference case scenario provided 

the point of comparison for the other 

two scenarios. The other two renewable 

fuel scenarios for 2012 represented the 


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110 GREET version 1.7, released November 10, 

2006. 

RFS program requirements and the 

volume projected by EIA. 

In both the RFS and EIA scenarios, we 

assumed that the biodiesel production 

volume would be 0.303 billion gallons 

based on EIA AEO2006 projections. 

Furthermore, for both scenarios we 

assume that 250 million gallons of 

ethanol that qualify for cellulosic 

biomass ethanol credit will be produced 

in 2012 from corn using biomass as the 

process energy source. The remaining 

renewable fuel volumes in each scenario 

would be ethanol made from corn and 

imports. The import volume is based on 

EIA’s projections for the percent of total 

ethanol volume supplied by imports in 

2012. The total volumes for all three 

scenarios are shown in Table II.A.1–1. 

For the purposes of calculating this 

difference or the amount of 

conventional fuel no longer consumed— 

that is, displaced—as a result of the use 

of the replacement renewable fuel, we 

assumed the ethanol volumes shown in 

Table II.A.1–1 are 5% denatured. The 

ethanol volumes were adjusted down to 

represent pure (100%) ethanol, 

biodiesel volumes were not adjusted. 

The adjusted volumes were then 

converted to total Btu using the 

appropriate volumetric energy content 

values (76,000 Btu/gal for ethanol, 

115,000 Btu/gal for gasoline, 118,000 

Btu/gal for biodiesel, and 130,000 Btu/ 

gal for diesel fuel). We make the 

assumption that vehicle energy 

efficiency will not be affected by the 

presence of renewable fuels (i.e., 

efficiency of combusting one Btu of 

ethanol is equal to the efficiency of 

combusting one Btu of gasoline). 

This lifecycle analysis is conducted 

without any regard to the geographic 

attributes of where emissions or energy 

use occurs; the model represents global 

reductions in GHG emissions and 

energy use, not just those occurring in 

the U.S. For example, under a full 

lifecycle assessment approach, the 

savings associated with reducing 

overseas crude oil extraction and 

refining are included, as are the 

international emissions associated with 

producing imported ethanol. There were 

two exceptions to this, both dealing 

with secondary impacts that may result 

internationally due to the expanded use 

of renewable fuels within the United 

States. 

The first exception is the emissions 

associated with international land use 

change. Due to decreasing corn exports 

some changes to international land use 

may occur, for example, as more crops 

are planted in other regions to 

compensate for the decrease in crop 

exports from the U.S. While the 

emissions associated with domestic 

land use change are well understood 

and are included in our lifecycle 

analysis, we did not include the 

potential impact on international land 

use and any emissions that might 

directly result. Our currently modeling 

capability does not allow us to assess 

what international land use changes 

would occur or how these changes 

would affect greenhouse gas emissions. 

For example, we would need to know 

how international cropping patterns 

would change as well as farming inputs 

and practices that might affect 

emissions assessment. 

The second case where we have not 

quantified the international impacts 

results from any reduction in world oil 

prices would tend to result from 

decreased demand in the U.S. as 

renewable fuels replace oil. It is 

commonly presumed in economic 

analyses that all else being equal 

quantity demanded of a valuable good 

(i.e., oil) will increase as price 

decreases. A world wide reduction of oil 

price would tend to reduce the cost of 

producing transportation fuel which in 

turn would tend to reduce the price 

consumers internationally would have 

to pay for this fuel. 

To the extent fuel prices are 

decreased, demand and consumption 

would tend to increase; this impact of 

reduced cost of driving is sometimes 

referred to as a ‘‘rebound effect.’’ Such 

a greater consumption internationally 

would presumably result in an increase 

in greenhouse gas emissions as 

consumers in the rest of the world drive 

more. These increased emissions would 

in part offset the emission impacts 

otherwise described in this preamble. 

While such international impacts of 

U.S. actions are important to 

understand, we have not have fully 

considered and quantified the 

international rebound effects of this 

renewable fuel standard. Nevertheless, 

such impacts remain an important 

consideration for future analysis. 

2. GREET Model 

As in the analyses for the proposal, 

for this final rulemaking we used the 

GREET fuel-cycle model. GREET has 

been under development for several 

years and has undergone extensive peer 

review through multiple updates. Of the 

available sources of information on 

lifecycle analyses of energy consumed 

and emissions generated, we believe 

that GREET offers the most 

comprehensive treatment of the 

transportation sector. For this final rule, 

we used an updated version of the 

GREET model 110, with a few 

modifications to its input assumptions. 

These changes since the NPRM are 

described below. 

The two main comments we received 

on our lifecycle modeling were that we 

should initiate a public dialogue on 

lifecycle analyses, models and 

assumptions, and that our sole reliance 

on the GREET model should be avoided, 

given other models are available. We 

have begun a public dialogue in that we 

identify the assumptions in the GREET 

model that were examined and modified 

for this final rulemaking. Furthermore, 

we will be initiating more 

comprehensive discussions about 

lifecycle analysis with stakeholders 

which could lead to an increased use of 

lifecycle analysis in future actions. 

In terms of our sole reliance on the 

GREET model, several other models 

have been developed for conducting 

renewable fuels lifecycle analysis. For 

example, researchers at the Energy and 

Resources Group (ERG) of the 

University of California Berkeley have 

developed the ERG Biofuel Analysis 

Meta-Model (EBAMM) and Mark 

Delucchi at the Institute of 

Transportation Studies of the University 

of California Davis has developed the 

Lifecycle Emissions Model (LEM). Other 

non-fuel specific lifecycle modeling 

tools could also be used to perform 

renewable fuel lifecycle analysis. 

Several studies have been released 

recently making use of these other 

models and showing different results 

than we find in the analysis done for 

this rule. For example, whereas GREET 

estimates a net GHG reduction of about 

22% for corn ethanol compared to 

gasoline, the previously cited works by 

Farrell et al. utilizing the EBAMM show 

around a 13% reduction. The main 

difference in results is not due to the 

model used but assumptions on scope 

and input data. 

For example, most studies focus on 

average or current ethanol production 

which uses a current mix of wet and dry 

mill ethanol production and use of coal 

and natural gas as process energy. In 

contrast, for this rulemaking we 

consider future increases in renewable 

fuel production so we focus on new 

production capacity which will rely 

more heavily on more efficient dry mill 

production than the current mix of wet 

and dry mill capacities. Other studies 

also typically base ethanol and farm 

energy use on historic data while we are 

assuming future capacity increases will 

use a state of the art dry milling plant 

and most current farming energy use 


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111Baseline Energy Consumption Estimates for 

Natural Gas and Coal-based Ethanol Plants—The 

Potential Impact of Combined Heat and Power 

(CHP), Prepared for: U.S. Environmental Protection 

Agency Combined Heat & Power Partnership, 

Prepared by: Energy and Environmental Analysis, 

Inc., July 2006. 

data. Varying assumptions concerning 

how land use change impact CO2

emissions and agriculture related GHG 

emissions could also have an impact on 

overall results. Other studies also differ 

in the environmental flows considered. 

For example, GREET uses the 

internationally accepted set of 

greenhouse gases while Delucchi uses 

additional types of greenhouse gases. 

We have not had an opportunity to 

develop comparable analyses of the 

GHG and energy impacts of this rule 

using these other models. However, as 

discussed in chapters 6.1.1 and 6.2.3 of 

the RIA, we believe the scope of the 

GREET model and the assumptions we 

have used in running the model tend 

toward the middle of the range. 

Therefore we believe these results 

provide a reasonable assessment of the 

energy and GHG impacts of the 

expanded use of renewable fuels. 

a. Renewable Fuel Pathways Considered 

The feedstocks and processes used to 

model renewable fuel production were 

those which our analysis in Chapter 1 

of the RIA shows will primarily be used 

through 2012. However, other pathways 

for producing renewable fuels may 

become popular such as producing 

cellulosic biomass ethanol from 

municipal solid waste as well as 

different process for the feedstocks 

considered, like gasification of 

switchgrass and production of 

‘‘renewable’’ diesel fuel through 

hydrotreating vegetable oils. 

Furthermore, the lifecycle analysis 

used for this rulemaking is based on 

averages of the different renewable fuels 

modeled. For example, the GHG 

emission and fossil energy savings 

associated with increased use of corn 

ethanol are calculated based on a mix of 

corn wet and dry milling, assuming a 

certain projected mix of each process. 

While this method may not exactly 

represent the reductions associated with 

a given gallon of renewable fuel, it is 

accurate for the purpose of this analysis 

which is to determine the impact of the 

total increased volume of renewable 

fuels used. 

We recognize that different feedstocks 

and processes will each have unique 

characteristics when it comes to 

lifecycle GHG emissions and energy use. 

However, we understand that other 

feedstocks and processes as well as 

differences in other parts of the 

renewable fuel lifecycle will impact the 

savings associated with their use and 

this is the focus of ongoing work at the 

agency. 

b. Modifications to GREET 

Since the analysis done for the NPRM, 

we have updated the GREET model with 

the following changes: 

—Included CO2 emissions from corn 

farming lime use. 

—Updated the corn farming fertilizer 

use inputs. 

—Added cellulosic biomass ethanol 

production from corn stover and 

forest waste. 

—Modeled biomass as a process fuel 

source in corn ethanol dry milling. 

In addition to the changes listed 

above we also examined and updated 

other GREET input assumptions for corn 

ethanol and biodiesel production. 

We also examined several other 

GREET input values, but determined 

that the default GREET values should 

not be changed for a variety of reasons. 

These included, corn and ethanol 

transport distances and modes and 

byproduct allocation methods. Our 

investigation of these other GREET 

input values are discussed more fully in 

Chapter 6 of the RIA. The current 

GREET default factors for these other 

inputs were included in the analysis for 

this final rule. 

We did not investigate the input 

values associated with the production of 

petroleum-based gasoline or diesel fuel 

in the GREET model for this final rule. 

However, the refinery modeling 

discussed in Section VII provides some 

additional information on the process 

energy requirements associated with the 

production of gasoline and diesel under 

a renewable fuels mandate. We will use 

information from this refinery modeling 

in future analysis to determine if any 

GREET input values should be changed. 

A summary of the GREET input 

values we investigated and modified for 

the final rule analysis is given below. 

Corn Farming Energy Use: Corn 

farming energy use was updated based 

on the most recent USDA Agricultural 

Resource Management Survey (ARMS) 

data. 

CO2 from Land Use Change: The 

GREET model has a default factor for 

CO2 from land use change that was 

included in the NPRM analysis. This 

factor was updated based on the results 

of the agricultural sector modeling 

outlined in Section X. The CO2

emissions from land use change used in 

the final rulemaking represents 

approximately 1% of total corn ethanol 

lifecycle GHG emissions. However, this 

value could be more significant if 

increased amounts of renewable fuels 

are used in the transportation sector. 

The issue of CO2 emissions from land 

use change associated with converting 

forest or Conservation Reserve Program 

(CRP) land into crop production for use 

in producing renewable fuels is an 

important factor to consider when 

determining the overall sustainability of 

renewable fuel use. While the analysis 

described above is indicating that the 

volumes of renewable fuel analyzed in 

this rulemaking will not cause a 

significant change in land use, this is an 

area we will continue to research for 

any future analysis. 

Corn Ethanol Wet-Mill Versus Dry 

Mill Plants: For this analysis, we expect 

most new ethanol plants will be dry 

mill operations. That has been the trend 

in the last few years as the demand for 

ethanol has grown, and our analysis of 

ethanol plants under construction and 

planned for the near future has verified 

this. Our analysis of production plans, 

as outlined in Section VI, indicates that 

essentially all new ethanol production 

will be from dry mill plants (99%). 

Corn Ethanol Dry Mill Plant Energy 

Use and Fuel Mix: Our review of plants 

under construction and those planned 

for the near future as outlined in Section 

VI, indicates that coal will be used as 

process fuel for approximately 14% of 

the new under construction and 

planned ethanol production volume 

capacity. The energy use at a dry mill 

plant using natural gas was based on the 

model developed by USDA and 

modified by EPA for use in the cost 

analysis of this rulemaking described in 

Section VII. For this analysis, we 

assumed that a coal plant would require 

15% 111 more electricity demand due to 

coal handling and have a 13% increase 

in thermal demand for steam dryers as 

compared to the natural gas fueled 

plant. We also considered a case where 

a corn ethanol plant utilized biomass as 

a fuel source. For this case we assumed 

the same amount of fuel and purchased 

electricity energy per gallon as a coal 

powered plant. This assumption is 

based on the biomass plant having more 

fuel handling than a natural gas plant 

and producing steam for DDGS drying. 

Corn Ethanol Dry Mill Plant 

Production Yield: Modern ethanol 

plants are now able to produce more 

than 2.7 gallons of ethanol per bushel of 

corn compared with less than 2.4 

gallons of ethanol per bushel of corn in 

1980. The development of new enzymes 

continues to increase the potential 

ethanol yield. We used a value of 


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23982 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

112All yield values presented represent pure 

ethanol production (i.e. no denaturant). 

113 ISO 14044:2006(E), ‘‘Environmental 

Management—Life Cycle Assessment— 

Requirements and Guidelines’’, International 

Organization for Standardization (ISO), First 

edition, 2006–07–01, Switzerland. 

2.71 112 gal/bu in our analysis, which 

may underestimate actual future yields. 

For additional information on our yield 

analysis, see the cost modeling of corn 

ethanol discussed in Section VII. 

Corn Ethanol Co-Products: We based 

the amount of DDGS produced by an 

ethanol dry mill plant on the USDA 

model used in the cost analysis work of 

this rulemaking, described in Section 

VII. Based on the agricultural sector 

modeling outlined in Section X, we 

assumed that one ton of DDGS displaces 

0.5 tons of corn and 0.5 tons of soybean 

meal. We also assume for corn ethanol 

wet milling that one ton of corn gluten 

meal substitutes for one ton of soybean 

meal, one ton of corn gluten feed 

substitutes for 0.5 tons of corn, and one 

ton of corn oil substitutes for one ton of 

soybean oil. 

Biodiesel Production: Two scenarios 

for biodiesel production were 

considered, one utilizing soybean oil as 

a feedstock and one using yellow grease. 

For the soybean oil scenario, the energy 

use and inputs for the biodiesel 

production process were based on a 

model developed by NREL and used by 

EPA in the cost modeling of soybean oil 

biodiesel, as discussed in Section VII. 

The GREET model does not have a 

specific case of biodiesel production 

from yellow grease. Therefore, as a 

surrogate we used the soybean oil based 

model with several adjustments. For the 

yellow grease case, we did not include 

soybean agriculture emissions or energy 

use. Soybean crushing was still 

included as a surrogate for yellow grease 

processing (purification, water removal, 

etc.). Also, due to additional processing 

requirements, the energy use associated 

with producing biodiesel from yellow 

grease is higher than for soybean oil 

biodiesel production. As per the cost 

modeling of yellow grease biodiesel 

discussed in Section VII, the energy use 

for yellow grease biodiesel production 

was assumed to be 1.72 times the energy 

used for soybean oil biodiesel. 

Biodiesel Transportation: Biodiesel 

transportation was based on the 

distribution infrastructure modeling for 

this rulemaking which indicates 

pipelines are not currently used to 

transport biodiesel and are not projected 

to play a role in biodiesel transport in 

the future time frame considered. 

Therefore, GREET default factors for 

biodiesel transportation from plant to 

terminal were modified to remove 

pipeline transport. 

c. Sensitivity Analysis 

As mentioned above, the results of 

lifecycle analysis are highly dependent 

on the input data assumptions used. 

Section IX.A.1.b outlined changes made 

to the GREET model inputs to better 

represent the scope and purpose of our 

analysis for this rulemaking. However, 

we also performed several sensitivity 

analyses on some key assumptions to 

see how varying them would impact 

overall results. 

We performed a sensitivity analysis 

on expanding the lifecycle fuel 

production system boundaries to 

include farm equipment production 

(e.g., emissions and energy use 

associated with producing steel, rubber, 

etc. used to make farming equipment). 

It was found that including farm 

equipment production energy use and 

emissions increases ethanol lifecycle 

energy use and GHG emissions by 

approximately 1 percent. Therefore, the 

lifecycle results are not changed 

significantly due to this expansion of 

system boundaries. 

We also performed a sensitivity 

analysis on the allocation method used 

in ethanol production. A number of byproducts are made during the 

production of ethanol. In lifecycle 

analyses, the energy consumed and 

emissions generated by an ethanol plant 

must be allocated not only to ethanol, 

but also to each of the by-products. 

There are a number of methods that can 

be used to estimate by-product 

allocations. The displacement method 

for by-product allocation, described in 

Section 6.1.2.10 of the RIA, is the 

default for the GREET model and is the 

method used by EPA. However, we 

evaluated another method, the process 

energy approach, to determine the 

impact this assumption has on the 

overall results of the analysis. 

Use of the process energy based 

allocation method reduces ethanol 

lifecycle energy use and GHG emissions 

by approximately 30 percent compared 

to the displacement allocation 

approach. This indicates that ethanol 

lifecycle analysis results are extremely 

sensitive to the choice of allocation 

method used. (See the RIA, Chapter 6 

for more information on these two byproduct allocation methods) The 

displacement allocation method is the 

method supported by international 

lifecycle assessment standards 113 and 

therefore EPA feels that it is the most 

accurate and preferred method to use. 

This does however highlight the 

sensitivity of lifecycle analysis results to 

choice of input parameters and 

assumptions. 

3. Displacement Indexes (DI) 

The displacement index (DI) 

represents the percent reduction in GHG 

emissions or fossil fuel energy brought 

about by the use of a renewable fuel in 

comparison to the conventional gasoline 

or diesel that the renewable fuel 

replaces. The formula for calculating the 

displacement index depends on which 

fuel is being displaced (i.e. gasoline or 

diesel), and which endpoint is of 

interest (e.g. petroleum energy, GHG). 

For instance, when investigating the 

CO2 impacts of ethanol used in gasoline, 

the displacement index is calculated as 

follows: 

DICO2 = −1 lifecycle CO emitted for ethanol in g/Btu

lifecycl

2

e CO emitted for gasoline in g/Btu 2

The units of g/Btu ensure that the 

comparison between the renewable fuel 

and the conventional fuel is made on a 

common basis, and that differences in 

the volumetric energy content of the 

fuels is taken into account. The 

denominator includes the CO2 emitted 

through combustion of the gasoline 

itself in addition to all the CO2 emitted 

during its manufacturer and 

distribution. The numerator, in contrast, 

includes only the CO2 emitted during 

the manufacturer and distribution of 

ethanol, not the CO2 emitted during 

combustion of the ethanol. 

The combustion of biomass-based 

fuels, such as ethanol from corn and 

woody crops, generates CO2. However, 

in the long run the CO2 emitted from 

biomass-based fuels combustion does 

not increase atmospheric CO2

concentrations, assuming the biogenic 

carbon emitted is offset by the uptake of 

CO2 resulting from the growth of new 

biomass. Thus ethanol’s carbon can be 

thought of as cycling from the 

environment into the plant material 


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used to make ethanol and, upon 

combustion of the ethanol, back into the 

environment from which it came. As a 

result, CO2 emissions from biomassbased fuels combustion are not included 

in their lifecycle emissions results and 

are not used in the CO2 displacement 

index calculations shown above. Net 

carbon fluxes from changes in biogenic 

carbon reservoirs in wooded or crop 

lands are accounted for separately in the 

GREET model. 

Using GREET, we calculated the 

lifecycle values for energy consumed 

and GHGs produced for corn-ethanol, 

cellulosic ethanol, and soybean-based 

biodiesel. These values were in turn 

used to calculate the displacement 

indexes. The results are shown in Table 

IX.A.3–1. Details of these calculations 

can be found in Chapter 6 of the RIA. 

TABLE IX.A.3–1.—DISPLACEMENT INDEXES DERIVED FROM GREET 

[In percent] 

Corn ethanol Corn ethanol 

(biomass fuel) Cellulosic ethanol Imported ethanol Biodiesel 

DIFossil Fuel ............................................... 39 .4 76 .3 92 .7 69 .0 61 .5 

DIPetroleum ................................................ 91 .8 92 .0 91 .7 92 .0 91 .2 

DIGHG ..................................................... 21 .8 54 .1 90 .9 56 .0 67 .7 

DICO2 ...................................................... 40 .3 72 .3 100 .1 71 .0 69 .8 

The displacement indexes in this 

table represent the impact of replacing 

a Btu of gasoline or diesel with a Btu of 

renewable fuel. Thus, for instance, for 

every Btu of gasoline which is replaced 

by corn ethanol, the total lifecycle GHG 

emissions that would have been 

produced from that Btu of gasoline 

would be reduced by 21.8 percent. For 

every Btu of diesel which is replaced by 

biodiesel, the total lifecycle petroleum 

energy that would have been consumed 

as a result of burning that Btu of diesel 

fuel would be reduced by 91.2 percent. 

Consistent with the cost modeling 

done for this rule, for the 2012 cases we 

assume the ‘‘cellulosic’’ ethanol volume 

is actually produced from corn utilizing 

a biomass fuel source at the ethanol 

production plant. The displacement 

index for that fuel as shown in Table 

IX.A.3–1 is used in the calculation of 

reductions. We have included the 

column for cellulosic ethanol for 

comparison, indicating that a move 

toward cellulosic ethanol will not 

displace petroleum much differently 

than other renewable fuels but will have 

a positive impact on GHG emissions 

reductions. 

For imported ethanol, it is more 

difficult to estimate the lifecycle energy 

and GHG displacement indexes since 

we know much less about how the crops 

used to make the ethanol are grown and 

what energy is used in the ethanol 

production facility. While not 

exclusively, we anticipate much 

imported ethanol to be primarily 

sugarcane based ethanol. 

The GHG emissions when producing 

sugarcane ethanol differs from corn 

ethanol in that the GHG emissions from 

growing sugarcane is likely different 

than for growing a equivalent amount of 

corn to make a gallon of ethanol. Also, 

the process of turning sugar into ethanol 

is easier than when starting with starch 

and therefore less energy intensive 

(which typically translates into lower 

GHG). Importantly, we understand that 

at least some of the ethanol produced in 

Brazil uses the bagasse from the 

sugarcane itself as a process fuel source. 

We know from our analysis that using 

a biomass source for process energy 

greatly improves the GHG benefit of the 

renewable fuel. These factors would 

result in sugarcane ethanol having a 

greater GHG benefit per gallon than corn 

ethanol, certainly where natural gas or 

coal is the typical process fuel source 

used. 

Conversely, sugarcane ethanol 

production does not result in a coproduct such as distillers grain as in the 

case of corn ethanol. In our analyses, 

accounting for co-products significantly 

improved the GHG displacement index 

for corn ethanol. Furthermore, there 

would be additional transportation 

emissions associated with transporting 

the imported ethanol to the U.S. as 

compared to domestically produced 

ethanol. Developing a technically 

rigorous lifecycle estimate for energy 

needs and GHG impacts for imported 

ethanol is not a simple task and was not 

available in the timeframe of this 

rulemaking. 

Considering all of the differences 

between imported and domestic 

ethanol, for this rulemaking, we 

assumed imported ethanol would be 

predominately from sugarcane and have 

estimated DI’s approximately mid-way 

between the DI’s for corn ethanol and 

DI’s for cellulosic ethanol. We are 

continuing to develop a better 

understanding of the lifecycle energy 

and GHG impacts of producing ethanol 

from sugarcane and other likely 

feedstock sources of imported ethanol 

for any future analysis. 

4. Impacts of Increased Renewable Fuel 

Use 

We used the methodology described 

above to evaluate impacts of increased 

use of renewable fuels on consumption 

of petroleum and fossil fuels and also on 

emissions of CO2 and GHGs. This 

section describes our results. 

a. Greenhouse Gases and Carbon 

Dioxide 

We estimated the reduction associated 

with the increased use of renewable 

fuels on lifecycle emissions of CO2 and 

total GHG. Since total GHG emission 

reductions are lower than CO2

reductions, this indicates that lifecycle 

emissions of CH4 and N2O are higher for 

renewable fuels than for the 

conventional fuels replaced. These 

values are then compared to the U.S. 

transportation sector emissions to get a 

percent reduction. The estimates for the 

2012 cases are presented in Table 

IX.A.4.a–1. 


wreier-aviles on DSK5TPTVN1PROD with RULES6
23984 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

114 Davis, Stacy C.; Diegel, Susan W., 

Transportation Energy Data Book: 25th Edition, Oak 

Ridge National Laboratory, U.S. Department of 

Energy, ORNL–6974, 2006. 

TABLE IX.A.4.A–1.—ESTIMATED CO2 AND GHG EMISSION IMPACTS OF INCREASED USE OF RENEWABLE FUELS IN THE

TRANSPORTATION SECTOR IN 2012, RELATIVE TO THE 2012 REFERENCE CASE

RFS case EIA case 

CO2 Reduction (million metric tons CO2) ................................................................................................................ 11 .0 19 .5 

Percent reduction in Transportation Sector CO Emissions .................................................................................... 0 .52 0 .93 

GHG Reduction (million metric tons CO2-eq.) ........................................................................................................ 8 .0 13 .1 

Percent reduction in Transportation Sector GHG Emissions .................................................................................. 0 .36 0 .59 

b. Fossil Fuel and Petroleum 

We estimated the reduction associated 

with the increased use of renewable 

fuels on lifecycle fossil fuels and 

petroleum. These values are then 

compared to the U.S. transportation 

sector emissions to get a percent 

reduction. The estimates for the 2012 

cases are presented in Table IX.A.4.b–1. 

TABLE IX.A.4.B–1.—ESTIMATED FOSSIL FUEL AND PETROLEUM IMPACTS OF INCREASED USE OF RENEWABLE FUELS IN

THE TRANSPORTATION SECTOR IN 2012, RELATIVE TO THE 2012 REFERENCE CASE

RFS case EIA case 

Fossil Fuel Reduction (quadrillion Btu) ................................................................................................................... 0 .15 0 .27 

Percent reduction in Transportation Sector Fossil Fuel Use .................................................................................. 0 .48 0 .85 

Petroleum Energy Reduction (billion gal.) ............................................................................................................... 2 .0 3 .9 

Percent reduction in Transportation Sector Petroleum Use ................................................................................... 0 .82 1 .60 

B. Implications of Reduced Imports of 

Petroleum Products 

In the proposal, we estimated the 

impact of expanded renewable fuel use 

on the importation of oil and finished 

transportation fuel. No comments were 

received suggesting alternative 

methodologies should be used. 

Therefore, we have incorporated that 

calculation in this final rule without 

change. 

In 2005, the United States imported 

almost 60 percent of the oil it 

consumed. This compares to just over 

35 percent of oil from imports in 

1975.114 Transportation accounts for 70 

percent of the U.S. oil consumption. It 

is clear that oil imports have a 

significant impact on the U.S. economy. 

Expanded production of renewable fuel 

is expected to contribute to energy 

diversification and the development of 

domestic sources of energy. We consider 

whether the RFS will reduce U.S. 

dependence on imported oil by 

calculating avoided expenditures on 

petroleum imports. Note that we do not 

calculate whether this reduction is on 

the net, socially beneficial, which 

would depend on the scarcity value of 

domestically produced ethanol versus 

that of imported petroleum products. 

However, the next section does discuss 

some of the energy security implications 

unique to petroleum imports. 

To assess the impact of the RFS 

program on petroleum imports, we 

estimate the fraction of domestic 

consumption derived from foreign 

sources using results from the AEO 

2006. We compared the levels and mix 

of imports in the AEO reference case 

with those in the low macroeconomic 

growth case and high oil price case. In 

Section 6.4.1 of the RIA we describe in 

greater detail how fuel producers may 

change their levels and mix of imports 

in response to a decrease in fuel 

demand. For the purposes of this 

rulemaking, we show values for the low 

macroeconomic growth comparison, 

where import reductions come almost 

entirely from imports of finished 

products as shown below in Table IX.B– 

1. The reductions in imports are 

compared to the AEO projected levels of 

net petroleum imports. The range of 

reductions in net petroleum imports are 

estimated to be between 0.9 to 1.7 

percent, as shown in Table IX.B–1. 

TABLE IX.B–1.—NET REDUCTIONS IN

IMPORTS IN 2012 

RFS case EIA case 

Reduction in finished 

products* (barrels 

per day) ................. 123,000 240,000 

Percent reduction** ... 0.89% 1.73% 

* Net reductions relative to 2012 reference 

case. 

** Compared to AEO 2006 projections for 

2012 reference case. 

We also calculate the change in 

expenditures in both petroleum and 

ethanol imports and compare these with 

the U.S. trade position measured as U.S. 

net exports of all goods and services 

economy-wide. The decreased 

expenditures were calculated by 

multiplying the changes in gasoline, 

diesel, and ethanol imports by the 

respective AEO 2006 wholesale 

gasoline, distillate, and ethanol price 

forecasts for the specific analysis years. 

In Table IX.B–2, the net expenditures in 

reduced petroleum imports, increased 

ethanol imports, and decreased corn 

exports are compared to the total value 

of U.S. net exports of goods and services 

for the whole economy for 2012. 

Relative to the 2012 projection, the 

avoided expenditures due to the RFS 

would represent 0.4 to 0.7% of 

economy-wide net exports. 


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115Leiby, Paul N., Donald W. Jones, T. Randall 

Curlee, and Russell Lee, Oil Imports: An 

Assessment of Benefits and Costs, ORNL–6851, Oak 

Ridge National Laboratory, November, 1997. 116The 1997 ORNL paper was cited and its 

results used in DOT/NHTSA’s rules establishing 

CAFE standards for 2008 through 2011 model year 

light trucks. See DOT/NHTSA, Final Regulatory 

Impacts Analysis: Corporate Average Fuel Economy 

and CAFE Reform MY 2008–2011, March 2006. 

117Stanford Energy Modeling Forum, Phillip C. 

Beccue and Hillard G. Huntington, ‘‘An Assessment 

of Oil Market Disruption Risks,’’ Final Report, EMF 

SR 8, October, 2005. 

TABLE IX.B–2.—AVOIDED IMPORT EXPENDITURES ($2004 BILLION) 

Cases AEO total net exports 

Expenditures on 

petroleum 

imports 

Expenditures on 

ethanol 

imports 

Decreased 

corn exports 

Net expenditures on 

imports 

Percent of 

total net 

exports 

RFS Case ..................................... ¥$383 (year 2012) ...................... ¥$2.6 +$0.7 +$0.6 ¥$1.4 0.4% 

EIA Case ...................................... ....................................................... ¥$5.1 +$1.0 +$1.3 ¥$2.8 0.7% 

C. Energy Security Implications of 

Increases in Renewable Fuels 

One of the effects of increased use of 

renewable fuels in the U.S. from the 

RFS is that it diversifies the energy 

sources in making transportation fuel. A 

potential disruption in supply reflected 

in the price volatility of a particular 

energy source carries with it both 

financial as well as strategic risks. These 

risks can be reduced to the extent that 

diverse sources of fuel energy reduce 

the dependence on any one source. This 

reduction in risks is a measure of 

improved energy security. 

At the time of the proposal, EPA 

stated that an analysis would be 

completed and estimates provided in 

support of this rule. In order to 

understand the energy security 

implications of the RFS, EPA has 

worked with Oak Ridge National 

Laboratory (ORNL), which has 

developed approaches for evaluating the 

social costs and energy security 

implications of oil use. In a new study 

produced for the RFS, entitled ‘‘The 

Energy Security Benefits of Reduced Oil 

Use, 2006–2015,’’ ORNL has updated 

and applied the method used in the 

1997 report ‘‘Oil Imports: An 

Assessment of Benefits and Costs’’, by 

Leiby, Jones, Curlee and Lee.115 116

While the 1997 report including a 

description of methodology and results 

at that time has been used or cited on 

a number of occasions, this updated 

analysis and results have not been 

available for full public consideration. 

Since energy security will be a key 

consideration in future actions aimed at 

reducing our dependence on oil, it is 

important to assure estimates of energy 

security impacts have been thoroughly 

examined in a full and open public 

forum. Since the updated analysis was 

only recently available, such a thorough 

analysis has not been possible. 

Therefore, EPA has decided to consider 

this update as a draft report, include it 

as part of the record of this rulemaking 

and invite further public analysis and 

consideration of both this particular 

draft report but also other perspectives 

on how to best quantify energy security 

benefits. To facilitate that additional 

consideration, we highlight below some 

of the key aspects of this particular draft 

analysis. 

The approach developed by ORNL 

estimates the incremental benefits to 

society, in dollars per barrel, of reducing 

U.S. oil imports, called ‘‘oil premium.’’ 

Since the 1997 publication of this 

report, changes in oil market conditions, 

both current and projected, suggest that 

the magnitude of the oil premium has 

changed. Significant driving factors that 

have been revised include: Oil prices, 

current and anticipated levels of OPEC 

production, U.S. import levels, the 

estimated responsiveness of regional oil 

supplies and demands to price, and the 

likelihood of oil supply disruptions. For 

this analysis, oil prices from the EIA’s 

AEO 2006 were used. Using the ‘‘oil 

premium’’ approach, estimates of 

benefits of improved energy security 

from reduced U.S. oil imports from 

increased use of renewable fuels are 

calculated. 

In conducting this analysis, ORNL 

considered the full economic cost of 

importing petroleum into the U.S. The 

full economic cost of importing 

petroleum into the U.S. is defined for 

this analysis to include two components 

in addition to the purchase price of 

petroleum itself. These are: (1) The 

higher costs for oil imports resulting 

from the effect of U.S. import demand 

on the world oil price and OPEC market 

power (i.e., the so called ‘‘demand’’ or 

‘‘monoposony’’ costs); and (2) the risk of 

reductions in U.S. economic output and 

disruption of the U.S. economy caused 

by sudden disruptions in the supply of 

imported oil to the U.S. (i.e., 

macroeconomic disruption/adjustment 

costs). 

1. Effect of Oil Use on Long-Run Oil 

Price, U.S. Import Costs, and Economic 

Output 

The first component of the full 

economic costs of importing petroleum 

into the U.S. follows from the effect of 

U.S. import demand on the world oil 

price over the long-run. Because the 

U.S. is a sufficiently large purchaser of 

foreign oil supplies, its purchases can 

affect the world oil price. This 

monopsony power means that increases 

in U.S. petroleum demand can cause the 

world price of crude oil to rise, and 

conversely, that reduced U.S. petroleum 

demand can reduce the world price of 

crude oil. Thus, one consequence of 

decreasing U.S. oil purchases due to 

increased use of renewable fuel is the 

potential decrease in the crude oil price 

paid for all crude oil purchased. 

2. Short-Run Disruption Premium From 

Expected Costs of Sudden Supply 

Disruptions 

The second component of the external 

economic costs resulting from U.S. oil 

imports arises from the vulnerability of 

the U.S. economy to oil shocks. The cost 

of shocks depends on their likelihood, 

size, and length, the capabilities of the 

market and U.S. Strategic Petroleum 

Reserve (SPR), the largest stockpile of 

government-owned emergency crude oil 

in the world, to respond, and the 

sensitivity of the U.S. economy to 

sudden price increases. While the total 

vulnerability of the U.S. economy to oil 

price shocks depends on the levels of 

both U.S. petroleum consumption and 

imports, variation in import levels or 

demand flexibility can affect the 

magnitude of potential increases in oil 

price due to supply disruptions. 

Disruptions are uncertain events, so the 

costs of alternative possible disruptions 

are weighted by disruption 

probabilities. The probabilities used by 

the ORNL study are based on a 2005 

Energy Modeling Forum117 synthesis of 

expert judgment and are used to 

determine an expected value of 

disruption costs, and the change in 

those expected costs given reduced U.S. 

oil imports. 

3. Costs of Existing U.S. Energy Security 

Policies 

The last often-identified component 

of the full economic costs of U.S. oil 


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118The RIA contains additional information on 

the renewable fuels volumes analyzed for this 

rulemaking. 

imports is the costs to the U.S. taxpayers 

of existing U.S. energy security policies. 

The two primary examples are 

maintaining a military presence to help 

secure stable oil supply from potentially 

vulnerable regions of the world and 

maintaining the SPR to provide buffer 

supplies and help protect the U.S. 

economy from the consequences of 

global oil supply disruptions. 

U.S. military costs are excluded from 

the analysis performed by ORNL 

because their attribution to particular 

missions or activities is difficult. Most 

military forces serve a broad range of 

security and foreign policy objectives. 

Attempts to attribute some share of U.S. 

military costs to oil imports are further 

challenged by the need to estimate how 

those costs might vary with incremental 

variations in U.S. oil imports. Similarly, 

while the costs for building and 

maintaining the SPR are more clearly 

related to U.S. oil use and imports, 

historically these costs have not varied 

in response to changes in U.S. oil 

import levels. Thus, while SPR is 

factored into the ORNL analysis, the 

cost of maintaining the SPR is excluded. 

As stated earlier, we have placed the 

draft report in the docket of this 

rulemaking for the purposes of inviting 

further consideration. However, the 

draft results of that report have not been 

used in quantifying the impacts of this 

rule. 

X. Agricultural Sector Economic 

Impacts 

As described in the Notice of 

Proposed Rulemaking (NPRM), we used 

the Forest and Agricultural Sector 

Optimization Model (FASOM) 

developed by Professor Bruce McCarl of 

Texas A&M University and others, to 

estimate the agricultural sector impacts 

of increasing renewable fuel volumes 

required by the RFS and for those 

volumes anticipated by EIA for 2012. 

Although current renewable fuel 

volume predictions are higher than the 

scenarios described in this rulemaking, 

we based our analysis on assumptions 

developed during the NPRM process. 

Our agricultural sector analysis 

considered the impacts of the domestic 

production of renewable fuels. 

Therefore, when we refer to either the 

RFS Case or the EIA Case, we include 

only renewable fuels produced from 

feedstocks grown in the U.S.118

At the time the NPRM was published, 

we had not yet finished our analysis of 

the agricultural impacts associated with 

the RFS. In the NPRM, we stated our 

intent to have the analysis completed in 

time for the Final Rulemaking (FRM). In 

the proposal we described our plan to 

evaluate the effect of increasing 

renewable fuels volumes on U.S. 

commodity prices, renewable fuel 

byproduct prices, livestock feed sources, 

land use, exports, and farm income. The 

results of this analysis are summarized 

in this section. Additional details are 

included in the Regulatory Impact 

Analysis (RIA). 

FASOM is a long-term economic 

model of the U.S. agriculture sector that 

attempts to maximize total revenues for 

producers while meeting the demands 

of consumers. Using a number of inputs, 

FASOM estimates which crops, 

livestock, and processed agricultural 

products will be produced in the U.S. 

The cost of these and other inputs are 

used to determine the price and level of 

production of commodities (e.g., field 

crops, livestock, and biofuel products). 

FASOM does not capture short-term 

fluctuations (i.e., month-to-month, 

annual) in prices and production, 

however, as it is designed to identify 

long-term trends (i.e., five to ten years). 

FASOM predicts that as renewable 

fuel volumes increase, corn prices will 

rise by about 18 cents (RFS Case) and 39 

cents (EIA Case) above the Reference 

Case price of $2.32 per bushel. For 

consistency, all of the dollar estimates 

are presented in 2004 dollars. Soybean 

prices will rise by about 18 cents (RFS 

Case) and 21 cents (EIA Case) above the 

Reference Case price of $5.26 per bushel 

by 2012. Since biodiesel volumes will 

not increase significantly in either the 

RFS or EIA scenarios, FASOM does not 

predict significant changes in the 

soybean related markets with respect to 

usage changes, or most other variables 

of interest for this rulemaking. The one 

exception is U.S. soybean exports, 

which are affected modestly. 

Changes in corn use can be seen by 

the changing percentage of corn used for 

ethanol. In 2005, approximately 12 

percent of the corn supply was used for 

ethanol production, however we 

estimate the amount of corn used for 

ethanol in 2012 will increase to 20 

percent (RFS Case) and 26 percent (EIA 

Case). 

The rising price of corn and soybeans 

has a direct impact on how corn is used. 

Higher domestic corn prices lead to 

lower U.S. exports as the world markets 

shift to other sources of these products 

or expand the use of substitute grains. 

FASOM estimates that U.S. corn exports 

will drop from about 2 billion bushels 

in our Reference Case, to 1.6 billion 

bushels (RFS Case) and 1.3 billion 

bushels (EIA Case) by 2012. U.S. exports 

of corn are estimated to drop by about 

19 percent by 2012 for the RFS Case and 

by roughly 38 percent in the EIA Case. 

In value terms, U.S. exports of corn fall 

by $573 million in the RFS Case and by 

$1.29 billion in the EIA Case in 2012. 

The impact on domestic livestock 

feed due to higher corn prices and 

higher U.S. demand for corn in ethanol 

is also partially offset by decreasing the 

use of corn for U.S. livestock feed. 

Substitutes are available for corn as a 

feedstock, and this market is price 

sensitive. One alternate feedstock is 

distillers dried grains with solubles 

(DDGS), a byproduct associated with the 

dry milling of ethanol production. Since 

FASOM predicts relatively flat prices 

for DDGS across all ethanol volume 

scenarios, the result is a significant 

increase in the use of DDGS as a feed 

source. We estimate DDGS in feed for 

the RFS case will almost double by 

2012, increasing from 8.5 million tons to 

15.2 million tons. Under the EIA Case, 

we expect DDGS to increase to 22.2 

million tons by 2012. 

The increase in soybean prices is 

estimated to cause a decline in U.S. 

soybean exports. In terms of export 

earnings, U.S. exports of soybeans fall 

by $220 million in the RFS Case and by 

$194 million in the EIA Case in 2012. 

The increase in renewable fuel 

production provides a significant 

increase in net farm income to the U.S. 

agricultural sector. FASOM predicts that 

in 2012, net U.S. farm income will 

increase by $2.6 billion dollars in the 

RFS renewable fuel volumes case (RFS 

Case) and $5.4 billion in the EIA 

renewable fuel volumes case (EIA Case). 

The RFS and EIA farm revenue 

increases represent roughly a 5 and 10 

percent increase, respectively, in U.S. 

net farm income from the sale of farm 

commodities over the Reference Case of 

roughly $53 billion. 

Higher corn prices will have a direct 

impact on the value of U.S. agricultural 

land. As demand for corn and farm 

products increases, the price of U.S. 

farm land will also increase. Our 

analysis shows that in 2012, higher 

renewable fuel volumes increase land 

prices by about 8 percent (RFS Case) 

and 17 percent (EIA Case). Much of the 

high quality, suitable land in the U.S. is 

already being used to produce corn. 

FASOM estimates an increase of 1.6 

million acres (RFS Case) and 2.6 million 

acres (EIA Case) above the 78.5 million 

corn acres harvested in the Reference 

Case in 2012. Due to this higher value 

of land, we are predicting that farms 

will withdraw a portion of the land 

currently in the Conservation Reserve 

Program (CRP), about 2.3 million acres 

(RFS Case) and 2.5 million acres (EIA 


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119Since much of the CRP land is ill suited for 

corn or soybean production, it is unlikely this land 

will go directly into corn or soybean production but 

instead will more likely be used to replace other 

agricultural land uses displaced by expanded corn 

and soybean production. 

Case) out of the approximately 40 

million acres in CRP.119

FASOM estimates U.S. annual 

wholesale food costs will increase by 

approximately $2.2 billion with the RFS 

renewable volumes and $3.7 billion 

with the EIA renewable volumes by 

2012. These costs translate to 

approximately $7 per person per year 

(RFS case) and $12 per person per year 

(EIA case). 

In the proposal, we noted that 

expansion in the use of renewable fuels 

also raises the issue of whether water 

quality and rural ecosystems in general 

could be affected due to increased 

production of agricultural feedstocks 

used to produce greater volumes of 

renewable fuels. We received one 

comment from Marathon asserting that 

our environmental assessment was 

incomplete and did not address water 

quality issues. In the time frame to 

complete this rulemaking, we were not 

able to conduct a comprehensive 

assessment of the environmental 

impacts in the agricultural sector of the 

wider use of renewable fuels. However, 

we have considered two indicators— 

fertilizer use on agricultural crops and 

Conservation Resource Program (CRP) 

lands—that may relate to environmental 

quality and water quality from the 

production of renewable fuels. The CRP 

is a voluntary program administered by 

the U.S. Department of Agriculture that 

helps defray the costs to farmers of 

taking agricultural lands out of 

production and placing them in CRP to 

provide environmental protection. 

As discussed in Section X, FASOM 

predicts the total amount of nitrogen 

applied on all farms will increase by 1.2 

percent in the RFS Case and by 2 

percent in the EIA Case, relative to the 

Reference Case in 2012. The total 

amount of phosphorous applied on all 

farms increases by 0.7 percent in the 

RFS Case and 1.2 percent in the EIA 

Case, relative to the Reference Case in 

2012. Currently, there are approximately 

40 million acres in the CRP. FASOM 

predicts 2.3 million acres (RFS Case) 

and 2.5 million acres (EIA Case) of land 

would be withdrawn from the CRP due 

to higher land values. 

XI. Public Participation 

Many interested parties participated 

in the rulemaking process that 

culminates with this final rule. This 

process provided opportunity for 

submitting written public comments 

following the proposal that we 

published on September 22, 2006 (71 FR 

55552). We considered these comments 

in developing the final rule. In addition, 

we held a public hearing on the 

proposed rulemaking on October 13, 

2006, and we have considered 

comments presented at the hearing. 

Throughout the rulemaking process, 

EPA met with stakeholders including 

representatives from the refining 

industry, renewable fuels production, 

and marketers and distributors, and 

others. The program we are finalizing 

today was developed as a collaborative 

effort with these stakeholders. 

We have prepared a detailed 

Summary and Analysis of Comments 

document, which describes comments 

we received on the proposal and our 

response to each of these comments. 

The Summary and Analysis of 

Comments is available in the docket for 

this rule at the Internet address listed 

under ADDRESSES, as well as on the 

Office of Transportation and Air Quality 

Web site (http://www.epa.gov/otaq/ 

renewablefuels/index.htm). In addition, 

comments and responses for key issues 

are included throughout this preamble. 

XII. Administrative Requirements 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order (EO) 12866, 

(58 FR 51735, October 4, 1993) this 

action is a ‘‘significant regulatory 

action’’ because of the policy 

implications of the final rule. Even 

though EPA has estimated that 

renewable fuel use through 2012 will be 

sufficient through the operation of 

market forces to meet the levels required 

in the standard, the final rule reflects 

the first renewable fuel mandate at the 

federal level. Accordingly, EPA 

submitted this action to the Office of 

Management and Budget (OMB) for 

review under EO 12866 and any 

changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. 

B. Paperwork Reduction Act 

The information collection 

requirements in this final rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The Information Collection 

Request (ICR) prepared by EPA has been 

assigned EPA ICR number 2242.02. The 

information collection requirements are 

not enforceable until OMB approves 

them. 

The information is planned to be 

collected to ensure that the required 

amount of renewable fuel is used each 

year. The credit trading program 

required by the Energy Policy Act will 

be satisfied through a program utilizing 

Renewable Identification Numbers 

(RINs), which are assigned when 

renewable fuel is produced in or 

imported to geographic areas covered by 

the rule. Production and importation of 

renewable fuel will serve as a surrogate 

measure of renewable fuel consumption. 

Our final RIN-based program will fulfill 

all the functions of a credit trading 

program, and thus will meet the Energy 

Policy Act’s requirements. For each 

calendar year, each obligated party will 

be required to submit a report to the 

Agency documenting the RINs it 

acquired, and showing that the sum of 

all RINs acquired is equal to or greater 

than its renewable volume obligation. 

The Agency could then verify that the 

RINs used for compliance purposes 

were valid by simply comparing RINs 

reported by producers to RINs claimed 

by obligated parties. 

For fuel standards, Section 208(a) of 

the Clean Air Act requires that 

manufacturers provide information the 

Administrator may reasonably require to 

determine compliance with the 

regulations; submission of the 

information is therefore mandatory. We 

will consider confidential all 

information meeting the requirements of 

Section 208(c) of the Clean Air Act. 

The annual public reporting and 

recordkeeping burden for this collection 

of information is estimated to be 3.3 

hours per response. A document 

entitled ‘‘Information Collection 

Request (ICR); OMB–83 Supporting 

Statement, Environmental Protection 

Agency, Office of Air and Radiation,’’ 

has been placed in the public docket. 

The supporting statement provides a 

detailed explanation of the Agency’s 

estimates by collection activity and 

explains how comments may be 

submitted by interested parties. The 

estimates contained in the docket are 

briefly summarized here: 

Estimated total number of potential 

respondents: 6,425. 

Estimated total number of responses: 

13,380. 

Estimated total annual burden hours: 

43,030. 

Estimated total respondent cost 

(estimated at $71 per hour): $3,055,130. 

Estimated total non-postage 

purchased services (estimated at $142 

per hour): $5,219,920. 

EPA received various comments on 

the rulemaking provisions covered by 

the proposed ICR. All comments that 

were submitted to EPA are considered 

in the Summary and Analysis of 

Comments, which can be found in the 


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120 In the NPRM, we also referred to a 125,000 

barrels of crude per day (bpcd) crude capacity limit. 

This criterion was inadvertently used and is not 

applicable for this program (as it only applies in 

cases of government procurement). We note that the 

number of small entities remains the same whether 

this criterion is used or not. 

docket. In response to comments, we 

have increased the frequency of 

reporting for transaction and summary 

reports from annually to quarterly. We 

have also removed a burden for small 

refiners that was associated with 

applying for small-refiner flexibilities. 

The burdens and costs shown above 

account for these changes. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. When 

this ICR is approved by OMB, the 

Agency will publish a technical 

amendment to 40 CFR part 9 in the 

Federal Register to display the OMB 

control number for the approved 

information collection requirements 

contained in this final rule. 

C. Regulatory Flexibility Act 

1. Overview 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201 (see table below); (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. The following 

table provides an overview of the 

primary SBA small business categories 

potentially affected by this regulation: 

Industry 

Defined as 

small entity by 

SBA if 

NAICS 

codes a

Gasoline refiners.≤1,500 employees.120.324110 

a North American Industrial Classification 

System. 

EPA has determined that it is not 

necessary to prepare a regulatory 

flexibility analysis in connection with 

this final rule. 

2. Background 

Since the vast majority of crude oil 

produced in or imported into the U.S. 

is consumed as gasoline or diesel fuel, 

concerns about our dependence on 

foreign sources of crude oil has renewed 

interest in renewable transportation 

fuels. The passage of the Energy Policy 

Act of 2005 demonstrated a strong 

commitment on the part of U.S. 

policymakers to consider additional 

means of supporting renewable fuels as 

a supplement to petroleum-based fuels 

in the transportation sector. Section 

1501 of the Energy Policy Act, which 

was added to the CAA as Section 211(o), 

requires EPA to establish the RFS 

program to ensure that the pool of 

gasoline sold in the contiguous 48 states 

contains specific volumes of renewable 

fuel for each calendar year starting with 

2006. The Agency is required to set a 

standard for each year representing the 

amount of renewable fuel that obligated 

parties (e.g., refiners, blenders, and 

importers) must use as a percentage of 

gasoline sold or introduced into 

commerce, and the Agency is required 

to promulgate a credit trading program 

for the RFS program. 

3. Small Refineries Versus Small 

Refiners 

Title XV (Ethanol and Motor Fuels) of 

the Energy Policy Act provides, at 

Section 1501(a)(2) [42 U.S.C. 

7545(o)(9)(A)–(D)], special provisions 

for ‘‘small refineries’’, such as a 

temporary exemption from the 

standards until calendar year 2011. The 

Act defines the term ‘‘small refinery’’ as 

‘‘* * * a refinery for which the average 

aggregate daily crude oil throughput for 

a calendar year * * * does not exceed 

75,000 barrels.’’ As shown in the table 

above, this term is different than SBA’s 

small business category for gasoline 

refiners, which is what the Regulatory 

Flexibility Act is concerned with. EPA 

is required under the RFA to consider 

impacts on small entities meeting SBA’s 

small business definition; these entities 

are referred to as ‘‘small refiners’’ for 

our regulatory flexibility analysis under 

SBREFA. 

A small refinery, per the Energy 

Policy Act, is a refinery where the 

annual crude throughput is less than or 

equal to 75,000 barrels (i.e., a smallcapacity refinery), and could be owned 

by a larger refiner that exceeds SBA’s 

small entity size standards. The small 

business employee criteria were 

established for SBA’s small business 

definition to set apart those companies 

which are most likely to be at an 

inherent economic disadvantage relative 

to larger businesses. 

4. Summary of Potentially Affected 

Small Entities 

The refiners that are potentially 

affected by this rule are those that 

produce gasoline. For our recent final 

rule ‘‘Control of Hazardous Air 

Pollutants From Mobile Sources’’ (72 FR 

8428, February 26, 2007), we performed 

an industry characterization of 

potentially affected gasoline refiners. 

We used that industry characterization 

to determine which refiners would also 

meet the SBA definition of a small 

entity. From that industry 

characterization, and further analysis 

following the Notice of Proposed 

Rulemaking (71 FR 55552, September 

22, 2006), we have determined that 

there are 15 gasoline refiners who own 

16 refineries (14 refiners own one 

refinery each, the remaining refiner 

owns two refineries) that meet the 

definition of a small refiner. Of the 16 

refineries, 13 also meet the Energy 

Policy Act’s definition of a small 

refinery. 

5. Impact of the Regulations on Small 

Entities 

As previously stated, many aspects of 

the RFS program, such as the required 

amount of annual renewable fuel 

volumes, are specified in the Energy 

Policy Act. As discussed above in 

Section II.A.1, the annual projections of 

ethanol production to satisfy market 

demand exceed the required annual 

renewable fuel volumes. When the 

small refinery exemption ends, it is 

anticipated that there will be over one 


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billion gallons in excess RINs available. 

We believe that this large volume of 

excess RINs will also lower the costs of 

this program. Thus, with the short-term 

relief provided under the Energy Policy 

Act for small refineries, and the 

anticipated low cost of RINs when the 

exemption expires, we believe that this 

program will not impose a significant 

economic burden on small refineries, 

small refiners, or any other obligated 

party. Therefore, we have determined 

that this rule will not have a significant 

economic impact on a substantial 

number of small entities. 

When the Agency certifies that a rule 

will not have a significant economic 

impact on a substantial number of small 

entities, EPA’s policy is to make an 

assessment of the rule’s impact on any 

small entities and to engage the 

potentially regulated entities in a dialog 

regarding the rule, and minimize the 

impact to the extent feasible. The 

following sections discuss our outreach 

with the potentially affected small 

entities and regulatory flexibilities to 

decrease the burden on these entities in 

compliance with the requirements of the 

RFS program. 

6. Small Refiner Outreach 

We do not believe that the RFS 

program would have a significant 

economic impact on a substantial 

number of small entities, however we 

have still tried to reduce the impact of 

this rule on small entities. Prior to 

issuing the proposed rule, we held 

meetings with small refiners to discuss 

the requirements of the RFS program 

and the special provisions offered by the 

Energy Policy Act for small refineries. 

The Energy Policy Act set out the 

following provisions for small 

refineries: 

• A temporary exemption from the 

Renewable Fuels Standard requirement 

until 2011; 

• An extension of the temporary 

exemption period for at least two years 

for any small refinery where it is 

determined that the refinery would be 

subject to a disproportionate economic 

hardship if required to comply; 

• Any small refinery may petition, at 

any time, for an exemption based on 

disproportionate economic hardship; 

and, 

• A small refinery may waive its 

temporary exemption to participate in 

the credit generation program, or it may 

also ‘‘opt-in’’, by waiving its temporary 

exemption, to be subject to the RFS 

requirement. 

During these meetings with the small 

refiners we also discussed the impacts 

of these provisions being offered to 

small refineries only. Three refiners met 

the definition of a small refiner, but 

their refineries did not meet the Act’s 

definition of a small refinery; which 

naturally concerned the small refiners. 

Another concern that the small refiners 

had was that if this rule were to have 

a significant economic impact on a 

substantial number of small entities a 

lengthy SBREFA process would ensue 

(which would delay the promulgation of 

the RFS rulemaking) and thus provide 

less lead time for these small entities 

prior to the RFS program start date. 

Following our discussions with the 

small refiners, they provided three 

suggested regulatory flexibility options 

that they believed could further assist 

affected small entities in complying 

with the RFS program standard: (1) That 

all small refiners be afforded the Act’s 

small refinery temporary exemption, (2) 

that small refiners be allowed to 

generate credits if they elect to comply 

with the RFS program standard prior to 

the 2011 small refinery compliance 

date, and (3) relieve small refiners who 

generate blending credits of the RFS 

program compliance requirements. 

We agreed with the small refiners’ 

suggestion that small refiners be 

afforded the same temporary exemption 

that the Act specifies for small 

refineries. This relief would apply to 

refiners who meet the 1,500 employee 

count criteria, as well as the crude 

capacity criteria that we have used in 

previous fuels programs when providing 

relief for small refiners. Regarding the 

small refiners’ second and third 

suggestions regarding credits, we note 

that the RIN-based program will 

automatically provide them with credit 

for any renewables that they blend into 

their motor fuels. Until 2011, small 

refiners will essentially be treated as 

oxygenate blenders and may separate 

RINs from batches and trade or sell 

these RINs, unless they choose to optin to the program. 

7. Reporting, Recordkeeping, and 

Compliance Requirements 

Registration, recordkeeping and 

reporting are necessary to track 

compliance with the renewable fuels 

standard and transactions involving 

RINs, and these compliance 

requirements will be similar to those 

required under our previous and current 

40 CFR part 80 fuel compliance 

programs. We will use the same basic 

forms for RFS program registration that 

we use under the reformulated gasoline 

(RFG) and anti-dumping program, as 

these forms are well known in the 

regulated community and are simple to 

fill out. We will use a simplified method 

of reporting via the Agency’s Central 

Data Exchange (CDX), which will 

reduce the reporting burden on 

regulated parties. Records related to RIN 

transactions may be kept in any format 

and the period of record retention by 

reporting parties is five years, similar to 

other fuel programs. Records to be 

retained include copies of all 

compliance reports submitted to EPA 

and copies of product transfer 

documents (PTDs). Sections IV and V, 

above, contain more detailed 

discussions on the registration, 

recordkeeping, reporting, and 

compliance requirements of this final 

rule. 

8. Related Federal Rules 

We are aware of a few other current 

or proposed Federal rules that are 

related to this rule. The primary related 

federal rules are the Mobile Source Air 

Toxics (MSAT2) rule (72 FR 8428, 

February 26, 2007), the Tier 2 Vehicle/ 

Gasoline Sulfur rulemaking (65 FR 

6698, February 10, 2000), and the fuel 

sulfur rules for highway diesel (66 FR 

5002, January 18, 2001) and nonroad 

diesel (69 FR 38958, June 29, 2004). 

9. Conclusions 

As stated above, based on the 

statutory relief provided by the Energy 

Policy Act for small refineries, we are 

certifying that this rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Additionally, we believe that extending 

the small refinery exemption to small 

refiners would further reduce the 

economic impacts on small entities. We 

believe that small refiners generally lack 

the resources available to larger 

companies, and therefore find it 

appropriate to extend this exemption to 

all small refiners. Thus, we are 

extending the small refinery temporary 

exemption to all qualified small 

refiners. Small refiners will also be 

permitted to separate RINs from batches 

and trade or sell these RINs prior to 

2011 if the small refiner operates as an 

ethanol blender. 

Past fuels rulemakings have included 

a provision that, for the purposes of the 

regulatory flexibility provisions for 

small entities, a refiner must also have 

an average crude capacity of no more 

than 155,000 barrels of crude per day 

(bpcd). To be consistent with these 

previous rules, we are finalizing in this 

rule that refiners that meet this criterion 

(in addition to having no more than 

1,500 total corporate employees) will be 

considered small refiners for the 

purposes of the regulatory flexibility 

provisions for this rulemaking. 

Since the RFS program would have no 

significant economic impact on a 

substantial number of small entities 


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with only the relief required in the 

Energy Policy Act for small refineries, it 

also follows that the rule will have no 

significant economic impact on a 

substantial number of small entities 

with the additional relief this final rule 

provides for small refiners. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective or least burdensome alternative 

that achieves the objectives of the rule. 

The provisions of section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. 

Before EPA establishes any regulatory 

requirements that may significantly or 

uniquely affect small governments, 

including tribal governments, it must 

have developed under Section 203 of 

the UMRA a small government agency 

plan. The plan must provide for 

notifying potentially affected small 

governments, enabling officials of 

affected small governments to have 

meaningful and timely input in the 

development of EPA regulatory 

programs with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that this rule 

does not contain a Federal mandate that 

may result in expenditures of $100 

million or more for State, local, and 

tribal governments, in the aggregate, or 

the private sector in any one year. EPA 

has estimated that renewable fuel use 

through 2012 will be sufficient to meet 

the required levels. Therefore, 

individual refiners, blenders, and 

importers are already on track to meet 

rule obligations through normal marketdriven incentives. Thus, today’s rule is 

not subject to the requirements of 

Sections 202 and 205 of the UMRA. 

EPA has determined that this rule 

contains no regulatory requirements that 

might significantly or uniquely affect 

small governments. Compliance with 

the mandates of the RFS rule, including 

the reporting and recordkeeping 

requirements, are the responsibility of 

exporters, producers, and importers of 

renewable fuel and gasoline, and not 

small governments. 

E. Executive Order 13132: Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ 

This final rule does not have 

federalism implications. It will not have 

substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. Thus, Executive 

Order 13132 does not apply to this rule. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicited comment on the 

proposed rule from State and local 

officials. A number of states commented 

on the proposed rule. These comments 

are available in the rulemaking docket, 

and are summarized and addressed in 

the Summary and Analysis document. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This final rule does not 

have tribal implications, as specified in 

Executive Order 13175. This rule will be 

implemented at the Federal level and 

will apply to refiners, blenders, and 

importers. Tribal governments will be 

affected only to the extent they purchase 

and use regulated fuels. Thus, Executive 

Order 13175 does not apply to this rule. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

Executive Order 13045: ‘‘Protection of 

Children from Environmental Health 

Risks and Safety Risks’’ (62 FR 19885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866, and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. 

EPA interprets EO 13045 as applying 

only to those regulatory actions that 

concern health or safety risks, such that 

the analysis required under section 5– 

501 of the EO has the potential to 

influence the regulation. This final rule 

is not subject to EO 13045 because it 

does not establish an environmental 

standard intended to mitigate health or 

safety risks and because it implements 

specific standards established by 

Congress in statutes. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not a ‘‘significant energy 

action’’ as defined in Executive Order 

13211, ‘‘Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use’’ (66 FR 28355 (May 

22, 2001)) because it is not likely to 

have a significant adverse effect on the 

supply, distribution, or use of energy. 

EPA expects the provisions to have 

very little effect on the national fuel 

supply since normal market forces alone 

are promoting greater renewable fuel 

use than required by the RFS mandate. 

We discuss our analysis of the energy 

and supply effects of the increased use 

of renewable fuels in Sections VI and X 

of this preamble. 

I. National Technology Transfer 

Advancement Act 

As noted in the proposed rule, 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law No. 

104–113, 12(d) (15 U.S.C. 272 note) 


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directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. The NTTAA directs EPA to 

provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This rulemaking involves technical 

standards. EPA has decided to use 

ASTM D6751–06a ‘‘Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate 

Fuels’’. This standard was developed by 

ASTM International (originally known 

as the American Society for Testing and 

Materials), Subcommittee D02.E0, and 

was approved in August 2006. The 

standard may be obtained through the 

ASTM Web site (www.astm.org) or by 

calling ASTM at (610) 832–9585. ASTM 

D6751–06a meets the objectives of this 

final rule because it establishes one of 

the criteria by which biodiesel is 

defined. 

J. Executive Order 12898: Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA lacks the discretionary authority 

to address environmental justice in this 

final rulemaking since the Agency is 

implementing specific standards 

established by Congress in statutes. 

Although EPA lacks authority to modify 

today’s regulatory decision on the basis 

of environmental justice considerations, 

EPA nevertheless determined that this 

final rule does not have a 

disproportionately high and adverse 

human health or environmental impact 

on minority or low-income populations. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A Major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). The effective 

date of the rule is September 1, 2007. 

L. Clean Air Act Section 307(d) 

This rule is subject to Section 307(d) 

of the CAA. Section 307(d)(7)(B) 

provides that ‘‘[o]nly an objection to a 

rule or procedure which was raised with 

reasonable specificity during the period 

for public comment (including any 

public hearing) may be raised during 

judicial review.’’ This section also 

provides a mechanism for the EPA to 

convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to the EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

the EPA should submit a Petition for 

Reconsideration to the Office of the 

Administrator, U.S. EPA, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460, with 

a copy to both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Director of the 

Air and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

U.S. EPA, 1200 Pennsylvania Ave., 

NW., Washington, DC 20460. 

XIII. Statutory Authority 

Statutory authority for the rules 

finalized today can be found in section 

211 of the Clean Air Act, 42 U.S.C. 

7545. Additional support for the 

procedural and compliance related 

aspects of today’s rule, including the 

recordkeeping requirements, come from 

Sections 114, 208, and 301(a) of the 

CAA, 42 U.S.C. 7414, 7542, and 7601(a). 

List of Subjects in 40 CFR Part 80 

Environmental protection, Air 

pollution control, Fuel additives, 

Gasoline, Imports, Incorporation by 

reference, Labeling, Motor vehicle 

pollution, Penalties, Reporting and 

recordkeeping requirements. 

Dated: April 10, 2007. 

Stephen L. Johnson, 

Administrator. 

■ 40 CFR part 80 is amended as follows: 

PART 80—REGULATION OF FUEL 

AND FUEL ADDITIVES 

■ 1. The authority citation for part 80 

continues to read as follows: 

Authority: 42 U.S.C. 7414, 7542, 7545, and 

7601(a). 

■ 2. Section 80.1100 is revised to read 

as follows: 

§ 80.1100 How is the statutory default 

requirement for 2006 implemented? 

(a) Definitions. For calendar year 

2006, the definitions of section 80.2 and 

the following additional definitions 

apply to this section. 

(1) Renewable fuel. (i) Renewable fuel 

means motor vehicle fuel that is used to 

replace or reduce the quantity of fossil 

fuel present in a fuel mixture used to 

operate a motor vehicle, and which: 

(A) Is produced from grain, starch, oil 

seeds, vegetable, animal, or fish 

materials including fats, greases, and 

oils, sugarcane, sugar beets, sugar 

components, tobacco, potatoes, or other 

biomass; or 

(B) Is natural gas produced from a 

biogas source, including a landfill, 

sewage waste treatment plant, feedlot, 

or other place where decaying organic 

material is found. 

(ii) The term ‘‘renewable fuel’’ 

includes cellulosic biomass ethanol, 

waste derived ethanol, biodiesel, and 

any blending components derived from 

renewable fuel. 

(2) Cellulosic biomass ethanol means 

ethanol derived from any lignocellulosic 

or hemicellulosic matter that is 

available on a renewable or recurring 

basis, including dedicated energy crops 

and trees, wood and wood residues, 

plants, grasses, agricultural residues, 

fibers, animal wastes and other waste 

materials, and municipal solid waste. 

The term also includes any ethanol 

produced in facilities where animal 

wastes or other waste materials are 

digested or otherwise used to displace 

90 percent or more of the fossil fuel 

normally used in the production of 

ethanol. 

(3) Waste derived ethanol means 

ethanol derived from animal wastes, 

including poultry fats and poultry 

wastes, and other waste materials, or 

municipal solid waste. 

(4) Small refinery means a refinery for 

which the average aggregate daily crude 


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oil throughput for a calendar year (as 

determined by dividing the aggregate 

throughput for the calendar year by the 

number of days in the calendar year) 

does not exceed 75,000 barrels. 

(5) Biodiesel means a diesel fuel 

substitute produced from nonpetroleum 

renewable resources that meets the 

registration requirements for fuels and 

fuel additives established by the 

Environmental Protection Agency under 

section 211 of the Clean Air Act. It 

includes biodiesel derived from animal 

wastes (including poultry fats and 

poultry wastes) and other waste 

materials, or biodiesel derived from 

municipal solid waste and sludges and 

oils derived from wastewater and the 

treatment of wastewater. 

(b) Renewable Fuel Standard for 2006. 

The percentage of renewable fuel in the 

total volume of gasoline sold or 

dispensed to consumers in 2006 in the 

United States shall be a minimum of 

2.78 percent on an annual average 

volume basis. 

(c) Responsible parties. Parties 

collectively responsible for attainment 

of the standard in paragraph (b) of this 

section are refiners (including blenders) 

and importers of gasoline. However, a 

party that is a refiner only because he 

owns or operates a small refinery is 

exempt from this responsibility. 

(d) EPA determination of attainment. 

EPA will determine after the close of 

2006 whether or not the requirement in 

paragraph (b) of this section has been 

met. EPA will base this determination 

on information routinely published by 

the Energy Information Administration 

on the annual domestic volume of 

gasoline sold or dispensed to U.S. 

consumers and of ethanol produced for 

use in such gasoline, supplemented by 

readily available information 

concerning the use in motor fuel of 

other renewable fuels such as cellulosic 

biomass ethanol, waste derived ethanol, 

biodiesel, and other non-ethanol 

renewable fuels. 

(1) The renewable fuel volume will 

equal the sum of all renewable fuel 

volumes used in motor fuel, provided 

that: 

(i) One gallon of cellulosic biomass 

ethanol or waste derived ethanol shall 

be considered to be the equivalent of 2.5 

gallons of renewable fuel; and 

(ii) Only the renewable fuel portion of 

blending components derived from 

renewable fuel shall be counted towards 

the renewable fuel volume. 

(2) If the nationwide average volume 

percent of renewable fuel in gasoline in 

2006 is equal to or greater than the 

standard in paragraph (b) of this section, 

the standard has been met. 

(e) Consequence of nonattainment in 

2006. In the event that EPA determines 

that the requirement in paragraph (b) of 

this section has not been attained in 

2006, a deficit carryover volume shall be 

added to the renewable fuel volume 

obligation for 2007 for use in calculating 

the standard applicable to gasoline in 

2007. 

(1) The deficit carryover volume shall 

be calculated as follows: 

DC = Vgas * (Rs¥Ra) 

Where: 

DC = Deficit carryover, in gallons, of 

renewable fuel. 

Vgas = Volume of gasoline sold or dispensed 

to U.S. consumers in 2006, in gallons. 

Rs = 0.0278. 

Ra = Ratio of renewable fuel volume divided 

by total gasoline volume determined in 

accordance with paragraph (d)(2) of this 

section. 

(2) There shall be no other 

consequence of failure to attain the 

standard in paragraph (b) of this section 

in 2006 for any of the parties in 

paragraph (c) of this section. 

■ 3. Section 80.1101 is added to read as 

follows: 

§ 80.1101 Definitions. 

The definitions of § 80.2 and the 

following additional definitions apply 

for the purposes of this subpart. For 

calendar year 2007 and beyond, the 

definitions in this section § 80.1101 

supplant those in § 80.1100. 

(a) Cellulosic biomass ethanol means 

either of the following: 

(1) Ethanol derived from any 

lignocellulosic or hemicellulosic matter 

that is available on a renewable or 

recurring basis and includes any of the 

following: 

(i) Dedicated energy crops and trees. 

(ii) Wood and wood residues. 

(iii) Plants. 

(iv) Grasses. 

(v) Agricultural residues. 

(vi) Animal wastes and other waste 

materials, the latter of which may 

include waste materials that are 

residues (e.g., residual tops, branches, 

and limbs from a tree farm). 

(vii) Municipal solid waste. 

(2) Ethanol made at facilities at which 

animal wastes or other waste materials 

are digested or otherwise used onsite to 

displace 90 percent or more of the fossil 

fuel that is combusted to produce 

thermal energy integral to the process of 

making ethanol, by: 

(i) The direct combustion of the waste 

materials or a byproduct resulting from 

digestion of such waste materials (e.g., 

methane from animal wastes) to make 

thermal energy; and/or 

(ii) The use of waste heat captured 

from an off-site combustion process as 

a source of thermal energy. 

(b) Waste derived ethanol means 

ethanol derived from either of the 

following: 

(1) Animal wastes, including poultry 

fats and poultry wastes, and other waste 

materials. 

(2) Municipal solid waste. 

(c) Biogas means methane or other 

hydrocarbon gas produced from 

decaying organic material, including 

landfills, sewage waste treatment plants, 

and animal feedlots. 

(d) Renewable fuel. (1) Renewable fuel 

is any motor vehicle fuel that is used to 

replace or reduce the quantity of fossil 

fuel present in a fuel mixture used to 

fuel a motor vehicle, and is produced 

from any of the following: 

(i) Grain. 

(ii) Starch. 

(iii) Oilseeds. 

(iv) Vegetable, animal, or fish 

materials including fats, greases, and 

oils. 

(v) Sugarcane. 

(vi) Sugar beets. 

(vii) Sugar components. 

(viii) Tobacco. 

(ix) Potatoes. 

(x) Other biomass. 

(xi) Natural gas produced from a 

biogas source, including a landfill, 

sewage waste treatment plant, feedlot, 

or other place where there is decaying 

organic material. 

(2) The term ‘‘Renewable fuel’’ 

includes cellulosic biomass ethanol, 

waste derived ethanol, biodiesel (monoalky ester), non-ester renewable diesel, 

and blending components derived from 

renewable fuel. 

(3) Ethanol covered by this definition 

shall be denatured as required and 

defined in 27 CFR parts 20 and 21. 

(4) Small volume additives (excluding 

denaturants) less than 1.0 percent of the 

total volume of a renewable fuel shall be 

counted as part of the total renewable 

fuel volume. 

(5) A fuel produced by a renewable 

fuel producer that is used in boilers or 

heaters is not a motor vehicle fuel and 

therefore is not a renewable fuel. 

(e) Blending component has the same 

meaning as ‘‘Gasoline blending stock, 

blendstock, or component’’ as defined at 

§ 80.2(s), for which the portion that can 

be counted as renewable fuel is 

calculated as set forth in § 80.1115(a). 

(f) Motor vehicle has the meaning 

given in Section 216(2) of the Clean Air 

Act (42 U.S.C. 7550). 

(g) Small refinery means a refinery for 

which the average aggregate daily crude 

oil throughput for the calendar year 

2004 (as determined by dividing the 


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aggregate throughput for the calendar 

year by the number of days in the 

calendar year) does not exceed 75,000 

barrels. 

(h) Biodiesel (mono-alkyl ester) means 

a motor vehicle fuel or fuel additive 

which is all the following: 

(1) Registered as a motor vehicle fuel 

or fuel additive under 40 CFR part 79. 

(2) A mono-alkyl ester. 

(3) Meets ASTM D–6751–07, entitled 

‘‘Standard Specification for Biodiesel 

Fuel Blendstock (B100) for Middle 

Distillate Fuels.’’ ASTM D–6751–07 is 

incorporated by reference. This 

incorporation by reference was 

approved by the Director of the Federal 

Register in accordance with 5 U.S.C. 

552(a) and 1 CFR part 51. A copy may 

be obtained from the American Society 

for Testing and Materials, 100 Barr 

Harbor Drive, West Conshohocken, 

Pennsylvania. A copy may be inspected 

at the EPA Docket Center, Docket No. 

EPA–HQ–OAR–2005–0161, EPA/DC, 

EPA West, Room 3334, 1301 

Constitution Ave., NW., Washington, 

DC, or at the National Archives and 

Records Administration (NARA). For 

information on the availability of this 

material at NARA, call 202–741–6030, 

or go to: http://www.archives.gov/ 

federal-register/cfr/ibr-locations.html. 

(4) Intended for use in engines that 

are designed to run on conventional 

diesel fuel. 

(5) Derived from nonpetroleum 

renewable resources (as defined in 

paragraph (m) of this section). 

(i) Non-ester renewable diesel means 

a motor vehicle fuel or fuel additive 

which is all the following: 

(1) Registered as a motor vehicle fuel 

or fuel additive under 40 CFR part 79. 

(2) Not a mono-alkyl ester. 

(3) Intended for use in engines that 

are designed to run on conventional 

diesel fuel. 

(4) Derived from nonpetroleum 

renewable resources (as defined in 

paragraph (m) of this section). 

(j) Renewable crude means 

biologically derived liquid feedstocks 

including but not limited to poultry fats, 

poultry wastes, vegetable oil, and 

greases that are used as feedstocks to 

make gasoline or diesel fuels at 

production units as specified in 

paragraph (k) of this section. 

(k) Renewable crude-based fuels are 

renewable fuels that are gasoline or 

diesel products resulting from the 

processing of renewable crudes in 

production units within refineries or at 

dedicated facilities within refineries, 

that process petroleum based feedstocks 

and which make gasoline and diesel 

fuel. 

(l) Importers. For the purposes of this 

subpart only, an importer of gasoline or 

renewable fuel is: 

(1) Any person who brings gasoline or 

renewable fuel into the 48 contiguous 

states of the United States from a foreign 

country or from an area that has not 

opted in to the program requirements of 

this subpart pursuant to § 80.1143; and 

(2) Any person who brings gasoline or 

renewable fuel into an area that has 

opted in to the program requirements of 

this subpart pursuant to § 80.1143. 

(m) Nonpetroleum renewable 

resources include, but are not limited to 

the following: 

(1) Plant oils. 

(2) Animal fats and animal wastes, 

including poultry fats and poultry 

wastes, and other waste materials. 

(3) Municipal solid waste and sludges 

and oils derived from wastewater and 

the treatment of wastewater. 

(n) Export of renewable fuel means: 

(1) Transfer of a batch of renewable 

fuel to a location outside the United 

States; and 

(2) Transfer of a batch of renewable 

fuel from a location in the contiguous 48 

states to Alaska, Hawaii, or a United 

States territory, unless that state or 

territory has received an approval from 

the Administrator to opt-in to the 

renewable fuel program pursuant to 

§ 80.1143. 

(o) Renewable Identification Number 

(RIN), is a unique number generated to 

represent a volume of renewable fuel 

pursuant to §§ 80.1125 and 80.1126. 

(1) Gallon-RIN is a RIN that represents 

an individual gallon of renewable fuel; 

and 

(2) Batch-RIN is a RIN that represents 

multiple gallon-RINs. 

(p) Neat renewable fuel is a renewable 

fuel to which only de minimus amounts 

of conventional gasoline or diesel have 

been added. 

§§ 80.1102 through 80.1103 [Reserved] 

■ 4. Sections 80.1102 and 80.1103 are 

reserved. 

■ 5. Sections 80.1104 through 80.1107 

are added to read as follows: 

Subpart K—Renewable Fuel Standard 

* * * * * 

Sec. 

80.1104 What are the implementation dates 

for the Renewable Fuel Standard 

Program? 

80.1105 What is the Renewable Fuel 

Standard? 

80.1106 To whom does the Renewable 

Volume Obligation apply? 

80.1107 How is the Renewable Volume 

Obligation calculated? 

* * * * * 

§ 80.1104 What are the implementation 

dates for the Renewable Fuel Standard 

Program? 

The RFS standards and other 

requirements of § 80.1101 and all 

sections following are effective 

beginning on September 1, 2007. 

§ 80.1105 What is the Renewable Fuel 

Standard? 

(a) The annual value of the renewable 

fuel standard for 2007 shall be 4.02 

percent. 

(b) Beginning with the 2008 

compliance period, EPA will calculate 

the value of the annual standard and 

publish this value in the Federal 

Register by November 30 of the year 

preceding the compliance period. 

(c) EPA will base the calculation of 

the standard on information provided 

by the Energy Information 

Administration regarding projected 

gasoline volumes and projected volumes 

of renewable fuel expected to be used in 

gasoline blending for the upcoming 

year. 

(d) EPA will calculate the annual 

renewable fuel standard using the 

following equation: 

RFStd RFV

G R GS RS GE i

i

ii i i i

= ∗ −

( ) − + − ( ) − 100 Celli

Where: 

RFStdi = Renewable Fuel Standard, in year 

i, in percent. 

RFVi = Nationwide annual volume of 

renewable fuels required by section 

211(o)(2)(B) of the Act (42 U.S.C. 7545), 

for year i, in gallons. 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states, in year i, in 

gallons. 

Ri = Amount of renewable fuel blended into 

gasoline that is projected to be used in 

the 48 contiguous states, in year i, in 

gallons. 

GSi = Amount of gasoline projected to be 

used in noncontiguous states or 

territories (if the state or territory optsin), in year i, in gallons. 


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RSi = Amount of renewable fuel blended into 

gasoline that is projected to be used in 

noncontiguous states or territories (if the 

state or territory opts-in), in year i, in 

gallons. 

GEi = Amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners, in year i, in gallons 

(through 2010 only, except to the extent 

that a small refinery exemption is 

extended pursuant to § 80.1141(e)). 

Celli = Beginning in 2013, the amount of 

renewable fuel that is required to come 

from cellulosic sources, in year i, in 

gallons. 

(e) Beginning with the 2013 

compliance period, EPA will calculate 

the value of the annual cellulosic 

standard and publish this value in the 

Federal Register by November 30 of the 

year preceding the compliance period. 

(f) EPA will calculate the annual 

cellulosic standard using the following 

equation: 

RF

G R GS RS ii i i

Cell Cell i

i = ∗ ( ) − + − ( ) 100

Where: 

RFCelli = Renewable Fuel Cellulosic 

Standard in year i, in percent. 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states, in year i, in 

gallons. 

Ri = Amount of renewable fuel blended into 

gasoline that is projected to be used in 

the 48 contiguous states, in year i, in 

gallons. 

GSi = Amount of gasoline projected to be 

used in noncontiguous states or 

territories (if the state or territory optsin), in year i, in gallons. 

RSi = Amount of renewable fuel blended into 

gasoline that is projected to be used in 

noncontiguous states or territories (if the 

state or territory opts-in), in year i, in 

gallons. 

Celli = Amount of renewable fuel that is 

required to come from cellulosic sources, 

in year i, in gallons. 

§ 80.1106 To whom does the Renewable 

Volume Obligation apply? 

(a) (1) An obligated party is a refiner 

that produces gasoline within the 48 

contiguous states, or an importer that 

imports gasoline into the 48 contiguous 

states. A party that simply adds 

renewable fuel to gasoline, as defined in 

§ 80.1107(c), is not an obligated party. 

(2) If the Administrator approves a 

petition of Alaska, Hawaii, or a United 

States territory to opt-in to the 

renewable fuel program under the 

provisions in § 80.1143, then ‘‘obligated 

party’’ shall also include any refiner that 

produces gasoline within that state or 

territory, or any importer that imports 

gasoline into that state or territory. 

(3) For the purposes of this section, 

‘‘gasoline’’ refers to any and all of the 

products specified at § 80.1107(c). 

(b) For each compliance period 

starting with 2007, any obligated party 

is required to demonstrate, pursuant to 

§ 80.1127, that it has satisfied the 

Renewable Volume Obligation for that 

compliance period, as specified in 

§ 80.1107(a). 

(c) An obligated party may comply 

with the requirements of paragraph (b) 

of this section for all of its refineries in 

the aggregate, or for each refinery 

individually. 

(d) An obligated party must comply 

with the requirements of paragraph (b) 

of this section for all of its imported 

gasoline in the aggregate. 

(e) An obligated party that is both a 

refiner and importer must comply with 

the requirements of paragraph (b) of this 

section for its imported gasoline 

separately from gasoline produced by its 

refinery or refineries. 

(f) Where a refinery or importer is 

jointly owned by two or more parties, 

the requirements of paragraph (b) of this 

section may be met by one of the joint 

owners for all of the gasoline produced 

at the refinery, or all of the imported 

gasoline, in the aggregate, or each party 

may meet the requirements of paragraph 

(b) of this section for the portion of the 

gasoline that it owns, as long as all of 

the gasoline produced at the refinery, or 

all of the imported gasoline, is 

accounted for in determining the 

renewable fuels obligation under 

§ 80.1107. 

(g) The requirements in paragraph (b) 

of this section apply to the following 

compliance periods: 

(1) For 2007, the compliance period is 

September 1 through December 31. 

(2) Beginning in 2008, and every year 

thereafter, the compliance period is 

January 1 through December 31. 

§ 80.1107 How is the Renewable Volume 

Obligation calculated? 

(a) The Renewable Volume Obligation 

for an obligated party is determined 

according to the following formula: 

RVOi = (RFStdi * GVi) + Di¥1

Where: 

RVOi = The Renewable Volume Obligation 

for an obligated party for calendar year 

i, in gallons of renewable fuel. 

RFStdi = The renewable fuel standard for 

calendar year i, determined by EPA 

pursuant to § 80.1105, in percent. 

GVi = The non-renewable gasoline volume, 

determined in accordance with 

paragraphs (b), (c), and (d) of this 

section, which is produced or imported 

by the obligated party in calendar year i, 

in gallons. 

Di¥1 = Renewable fuel deficit carryover from 

the previous year, per § 80.1127(b), in 

gallons. 

(b) The non-renewable gasoline 

volume for a refiner, blender, or 

importer for a given year, GVi, specified 

in paragraph (a) of this section is 

calculated as follows: 

GV G RB ix y

y

m

x

n

= − = =

∑ ∑ 1 1

Where: 

x = Individual batch of gasoline produced or 

imported in calendar year i. 

n = Total number of batches of gasoline 

produced or imported in calendar year i. 

Gx = Volume of batch x of gasoline produced 

or imported, in gallons. 

y = Individual batch of renewable fuel 

blended into gasoline in calendar year i. 

m = Total number of batches of renewable 

fuel blended into gasoline in calendar 

year i. 

RBy = Volume of batch y of renewable fuel 

blended into gasoline, in gallons. 

(c) All of the following products that 

are produced or imported during a 

compliance period, collectively called 

‘‘gasoline’’ for the purposes of this 

section (unless otherwise specified), are 

to be included in the volume used to 

calculate a party’s renewable volume 

obligation under paragraph (a) of this 

section, except as provided in paragraph 

(d) of this section: 

(1) Reformulated gasoline, whether or 

not renewable fuel is later added to it. 

(2) Conventional gasoline, whether or 

not renewable fuel is later added to it. 

(3) Reformulated gasoline blendstock 

that becomes finished reformulated 

gasoline upon the addition of oxygenate 

(‘‘RBOB’’). 

(4) Conventional gasoline blendstock 

that becomes finished conventional 

gasoline upon the addition of oxygenate 

(‘‘CBOB’’). 

(5) Blendstock (including butane and 

gasoline treated as blendstock 

(‘‘GTAB’’)) that has been combined with 

other blendstock and/or finished 

gasoline to produce gasoline. 

(6) Any gasoline, or any unfinished 

gasoline that becomes finished gasoline 

upon the addition of oxygenate, that is 

produced or imported to comply with a 

state or local fuels program. 

(d) The following products are not 

included in the volume of gasoline 

produced or imported used to calculate 

a party’s renewable volume obligation 

under paragraph (a) of this section: 

(1) Any renewable fuel as defined in 

§ 80.1101(d). 

(2) Blendstock that has not been 

combined with other blendstock or 

finished gasoline to produce gasoline. 

(3) Gasoline produced or imported for 

use in Alaska, Hawaii, the 

Commonwealth of Puerto Rico, the U.S. 

Virgin Islands, Guam, American Samoa, 

and the Commonwealth of the Northern 

Marianas, unless the area has opted into 

the RFS program under § 80.1143. 


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(4) Gasoline produced by a small 

refinery that has an exemption under 

§ 80.1141 or an approved small refiner 

that has an exemption under § 80.1142 

until January 1, 2011 (or later, for small 

refineries, if their exemption is 

extended pursuant to § 80.1141(e)). 

(5) Gasoline exported for use outside 

the 48 United States, and gasoline 

exported for use outside Alaska, Hawaii, 

the Commonwealth of Puerto Rico, the 

U.S. Virgin Islands, Guam, American 

Samoa, and the Commonwealth of the 

Northern Marianas, if the area has opted 

into the RFS program under § 80.1143. 

(6) For blenders, the volume of 

finished gasoline, RBOB, or CBOB to 

which a blender adds blendstocks. 

(7) The gasoline portion of transmix 

produced by a transmix processor, or 

the transmix blended into gasoline by a 

transmix blender, under 40 CFR 80.84. 

§§ 80.1108 through 80.1114 [Reserved] 

■ 6. Sections 80.1108 through 80.1114 

are reserved. 

■ 7. Section 80.1115 is added to read as 

follows: 

§ 80.1115 How are equivalence values 

assigned to renewable fuel? 

(a)(1) Each gallon of a renewable fuel 

shall be assigned an equivalence value 

by the producer or importer pursuant to 

paragraph (b) or (c) of this section. 

(2) The equivalence value is a number 

that is used to determine how many 

gallon-RINs can be generated for a batch 

of renewable fuel according to 

§ 80.1126. 

(b) Equivalence values shall be 

assigned for certain renewable fuels as 

follows: 

(1) Cellulosic biomass ethanol and 

waste derived ethanol produced on or 

before December 31, 2012 which is 

denatured shall have an equivalence 

value of 2.5. 

(2) Ethanol other than cellulosic 

biomass ethanol or waste-derived 

ethanol which is denatured shall have 

an equivalence value of 1.0. 

(3) Biodiesel (mono-alkyl ester) shall 

have an equivalence value of 1.5. 

(4) Butanol shall have an equivalence 

value of 1.3. 

(5) Non-ester renewable diesel, 

including that produced from 

coprocessing a renewable crude with 

fossil fuels in a hydrotreater, shall have 

an equivalence value of 1.7. 

(6) All other renewable crude-based 

renewable fuels shall have an 

equivalence value of 1.0. 

(c)(1) For renewable fuels not listed in 

paragraph (b) of this section, a producer 

or importer shall submit an application 

to the Agency for an equivalence value 

following the provisions of paragraph 

(d) of this section. 

(2) A producer or importer may also 

submit an application for an alternative 

equivalence value pursuant to 

paragraph (d) of this section if the 

renewable fuel is listed in paragraph (b) 

of this section, but the producer or 

importer has reason to believe that a 

different equivalence value than that 

listed in paragraph (b) of this section is 

warranted. 

(d) Determination of equivalence 

values. (1) Except as provided in 

paragraph (d)(4) of this section, the 

equivalence value for renewable fuels 

described in paragraph (c) of this 

section shall be calculated using the 

following formula: 

EV = (R / 0.931) * (EC / 77,550) 

Where: 

EV = Equivalence Value for the renewable 

fuel, rounded to the nearest tenth. 

R = Renewable content of the renewable fuel. 

This is a measure of the portion of a 

renewable fuel that came from a 

renewable source, expressed as a 

percent, on an energy basis. 

EC = Energy content of the renewable fuel, 

in Btu per gallon (lower heating value). 

(2) The application for an equivalence 

value shall include a technical 

justification that includes a description 

of the renewable fuel, feedstock(s) used 

to make it, and the production process. 

(3) The Agency will review the 

technical justification and assign an 

appropriate Equivalence Value to the 

renewable fuel based on the procedure 

in this paragraph (d). 

(4) For biogas, the Equivalence Value 

is 1.0, and 77,550 Btu of biogas is 

equivalent to 1 gallon of renewable fuel. 

§§ 80.1116 through 80.1124 [Reserved] 

■ 8. Sections 80.1116 through 80.1124 

are reserved. 

■ 9. Sections 80.1125 through 80.1132 

are added to read as follows: 

Subpart K—Renewable Fuel Standard 

* * * * * 

Sec. 

80.1125 Renewable Identification Numbers 

(RINs). 

80.1126 How are RINs generated and 

assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

80.1127 How are RINs used to demonstrate 

compliance? 

80.1128 General requirements for RIN 

distribution. 

80.1129 Requirements for separating RINs 

from volumes of renewable fuel. 

80.1130 Requirements for exporters of 

renewable fuels. 

80.1131 Treatment of invalid RINs. 

80.1132 Reported spillage of renewable 

fuel. 

* * * * * 

§ 80.1125 Renewable Identification 

Numbers (RINs). 

Each RIN is a 38 character numeric 

code of the following form: 

KYYYYCCCCFFFFFBBBBBRRD 

SSSSSSSSEEEEEEEE 

(a) K is a number identifying the type 

of RIN as follows: 

(1) K has the value of 1 when the RIN 

is assigned to a volume of renewable 

fuel pursuant to §§ 80.1126(e) and 

80.1128(a). 

(2) K has the value of 2 when the RIN 

has been separated from a volume of 

renewable fuel pursuant to 

§ 80.1126(e)(4) or § 80.1129. 

(b) YYYY is the calendar year in 

which the batch of renewable fuel was 

produced or imported. YYYY also 

represents the year in which the RIN 

was originally generated. 

(c) CCCC is the registration number 

assigned according to § 80.1150 to the 

producer or importer of the batch of 

renewable fuel. 

(d) FFFFF is the registration number 

assigned according to § 80.1150 to the 

facility at which the batch of renewable 

fuel was produced or imported. 

(e) BBBBB is a serial number assigned 

to the batch which is chosen by the 

producer or importer of the batch such 

that no two batches have the same value 

in a given calendar year. 

(f) RR is a number representing the 

equivalence value of the renewable fuel 

as specified in § 80.1115 and multiplied 

by 10 to produce the value for RR. 

(g) D is a number identifying the type 

of renewable fuel, as follows: 

(1) D has the value of 1 if the 

renewable fuel can be categorized as 

cellulosic biomass ethanol as defined in 

§ 80.1101(a). 

(2) D has the value of 2 if the 

renewable fuel cannot be categorized as 

cellulosic biomass ethanol as defined in 

§ 80.1101(a). 

(h) SSSSSSSS is a number 

representing the first gallon-RIN 

associated with a batch of renewable 

fuel. 

(i) EEEEEEEE is a number 

representing the last gallon-RIN 

associated with a batch of renewable 

fuel. EEEEEEEE will be identical to 

SSSSSSSS if the batch-RIN represents a 

single gallon-RIN. Assign the value of 

EEEEEEEE as described in § 80.1126. 

§ 80.1126 How are RINs generated and 

assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

(a) Regional applicability. (1) Except 

as provided in paragraph (b) of this 

section, a RIN must be assigned by a 

renewable fuel producer or importer to 

every batch of renewable fuel produced 

by a facility located in the contiguous 48 


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states of the United States, or imported 

into the contiguous 48 states. 

(2) If the Administrator approves a 

petition of Alaska, Hawaii, or a United 

States territory to opt-in to the 

renewable fuel program under the 

provisions in § 80.1143, then the 

requirements of paragraph (a)(1) of this 

section shall also apply to renewable 

fuel produced or imported into that 

state or territory beginning in the next 

calendar year. 

(b) Volume threshold. Renewable fuel 

producers located within the United 

States that produce less than 10,000 

gallons of renewable fuel each year, and 

importers that import less than 10,000 

gallons of renewable fuel each year, are 

not required to generate and assign RINs 

to batches of renewable fuel. Such 

producers and importers are also 

exempt from the registration, reporting, 

and recordkeeping requirements of 

§§ 80.1150–80.1152. However, for such 

producers and importers that 

voluntarily generate and assign RINs, all 

the requirements of this subpart apply. 

(c) Definition of batch. For the 

purposes of this section and § 80.1125, 

a ‘‘batch of renewable fuel’’ is a volume 

of renewable fuel that has been assigned 

a unique RIN code BBBBB within a 

calendar year by the producer or 

importer of the renewable fuel in 

accordance with the provisions of this 

section and § 80.1125. 

(1) The number of gallon-RINs 

generated for a batch of renewable fuel 

may not exceed 99,999,999. 

(2) A batch of renewable fuel cannot 

represent renewable fuel produced or 

imported in excess of one calendar 

month. 

(d) Generation of RINs. (1) Except as 

provided in paragraph (b) of this 

section, the producer or importer of a 

batch of renewable fuel must generate 

RINs for that batch, including any 

renewable fuel contained in imported 

gasoline. 

(2) A producer or importer of 

renewable fuel may generate RINs for 

volumes of renewable fuel that it owns 

on September 1, 2007. 

(3) A party generating a RIN shall 

specify the appropriate numerical 

values for each component of the RIN in 

accordance with the provisions of 

§ 80.1125 and this paragraph (d). 

(4) Except as provided in paragraph 

(d)(6) of this section, the number of 

gallon-RINs that shall be generated for a 

given batch of renewable fuel shall be 

equal to a volume calculated according 

to the following formula: 

VRIN = EV * Vs

Where: 

VRIN = RIN volume, in gallons, for use 

determining the number of gallon-RINs 

that shall be generated. 

EV = Equivalence value for the renewable 

fuel per § 80.1115. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(d)(7) of this section. 

(5) Multiple gallon-RINs generated to 

represent a given volume of renewable 

fuel can be represented by a single 

batch-RIN through the appropriate 

designation of the RIN volume codes 

SSSSSSSS and EEEEEEEE. 

(i) The value of SSSSSSSS in the 

batch-RIN shall be 00000001 to 

represent the first gallon-RIN associated 

with the volume of renewable fuel. 

(ii) The value of EEEEEEEE in the 

batch-RIN shall represent the last 

gallon-RIN associated with the volume 

of renewable fuel, based on the RIN 

volume determined pursuant to 

paragraph (d)(4) of this section. 

(6) (i) For renewable crude-based 

renewable fuels produced in a facility or 

unit that coprocesses renewable crudes 

and fossil fuels, the number of gallonRINs that shall be generated for a given 

batch of renewable fuel shall be equal to 

the gallons of renewable crude used 

rather than the gallons of renewable fuel 

produced. 

(ii) Parties that produce renewable 

crude-based renewable fuels in a facility 

or unit that coprocesses renewable 

crudes and fossil fuels may submit a 

petition to the Agency requesting the 

use of volumes of renewable fuel 

produced as the basis for the number of 

gallon-RINs, pursuant to paragraph 

(d)(4) of this section. 

(7) Standardization of volumes. In 

determining the standardized volume of 

a batch of renewable fuel for purposes 

of generating RINs under this paragraph 

(d), the batch volumes shall be adjusted 

to a standard temperature of 60 °F. 

(i) For ethanol, the following formula 

shall be used: 

Vs,e = Va,e * (¥0.0006301 * T + 1.0378) 

Where: 

Vs,e = Standardized volume of ethanol at 60 

°F, in gallons. 

Va,e = Actual volume of ethanol, in gallons. 

T = Actual temperature of the batch, in °F. 

(ii) For biodiesel (mono alkyl esters), 

the following formula shall be used: 

Vs,b = Va,b * (¥0.0008008 * T + 1.0480) 

Where: 

Vs,b = Standardized volume of biodiesel at 60 

°F, in gallons. 

Va,b = Actual volume of biodiesel, in gallons. 

T = Actual temperature of the batch, in °F. 

(iii) For other renewable fuels, an 

appropriate formula commonly 

accepted by the industry shall be used 

to standardize the actual volume to 60 

°F. Formulas used must be reported to 

the Agency, and may be reviewed for 

appropriateness. 

(8) (i) A party is prohibited from 

generating RINs for a volume of 

renewable fuel that it produces if: 

(A) The renewable fuel has been 

produced from a chemical conversion 

process that uses another renewable fuel 

as a feedstock; and 

(B) The renewable fuel used as a 

feedstock was produced by another 

party. 

(ii) Any RINs that the party acquired 

with renewable fuel used as a feedstock 

shall be assigned to the new renewable 

fuel that was made with that feedstock. 

(e) Assignment of RINs to batches. (1) 

Except as provided in paragraph (e)(4) 

of this section, the producer or importer 

of renewable fuel must assign all RINs 

generated to volumes of renewable fuel. 

(2) A RIN is assigned to a volume of 

renewable fuel when ownership of the 

RIN is transferred along with the 

transfer of ownership of the volume of 

renewable fuel, pursuant to § 80.1128(a). 

(3) All assigned RINs shall have a K 

code value of 1. 

(4) RINs not assigned to batches. (i) If 

a party produces or imports a batch of 

cellulosic biomass ethanol or wastederived ethanol having an equivalence 

value of 2.5, that party must assign at 

least one gallon-RIN to each gallon of 

cellulosic biomass ethanol or wastederived ethanol, representing the first 

1.0 portion of the Equivalence Value. 

(ii) Any remaining gallon-RINs 

generated for the cellulosic biomass 

ethanol or waste-derived ethanol which 

represent the remaining 1.5 portion of 

the Equivalence Value may remain 

unassigned. 

(iii) The producer or importer of 

cellulosic biomass ethanol or wastederived ethanol shall designate the K 

code as 2 for all unassigned RINs. 

§ 80.1127 How are RINs used to 

demonstrate compliance? 

(a) Renewable volume obligations. (1) 

Except as specified in paragraph (b) of 

this section, each party that is obligated 

to meet the Renewable Volume 

Obligation under § 80.1107, or each 

party that is an exporter of renewable 

fuels that is obligated to meet a 

Renewable Volume Obligation under 

§ 80.1130, must demonstrate pursuant to 

§ 80.1152(a)(1) that it has taken 

ownership of sufficient RINs to satisfy 

the following equation: 

(∑RINNUM)i + (∑RINNUM)i¥1 = RVOi

Where: 

(∑RINNUM)i = Sum of all owned gallon-RINs 

that were generated in year i and are 


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being applied towards the RVOi, in 

gallons. 

(∑RINNUM)i¥1 = Sum of all owned gallonRINs that were generated in year i¥1 

and are being applied towards the RVOi,

in gallons. 

RVOi = The Renewable Volume Obligation 

for the obligated party or renewable fuel 

exporter for calendar year i, in gallons, 

pursuant to § 80.1107 or § 80.1130. 

(2) For compliance for calendar years 

2008 and later, the value of 

(∑RINNUM)i¥1 may not exceed a value 

determined by the following inequality: 

(∑RINNUM)i¥1 ≤ 0.20 × RVOi

(3) RINs may only be used to 

demonstrate compliance with the RVO 

for the calendar year in which they were 

generated or the following calendar 

year. RINs used to demonstrate 

compliance in one year cannot be used 

to demonstrate compliance in any other 

year. 

(4) A party may only use a RIN for 

purposes of meeting the requirements of 

paragraphs (a)(1) and (a)(2) of this 

section if that RIN is an unassigned RIN 

with a K code of 2 obtained in 

accordance with §§ 80.1126(e)(4), 

80.1128, and 80.1129. 

(5) The number of gallon-RINs 

associated with a given batch-RIN that 

can be used for compliance with the 

RVO shall be calculated from the 

following formula: 

RINNUM = EEEEEEEE¥SSSSSSSS + 1 

Where: 

RINNUM = Number of gallon-RINs associated 

with a batch-RIN, where each gallon-RIN 

represents one gallon of renewable fuel 

for compliance purposes. 

EEEEEEEE = Batch-RIN component 

identifying the last gallon-RIN associated 

with the batch-RIN. 

SSSSSSSS = Batch-RIN component 

identifying the first gallon-RIN 

associated with the batch-RIN. 

(b) Deficit carryovers. (1) An obligated 

party or an exporter of renewable fuel 

that fails to meet the requirements of 

paragraphs (a)(1) or (a)(2) of this section 

for calendar year i is permitted to carry 

a deficit into year i+1 under the 

following conditions: 

(i) The party did not carry a deficit 

into calendar year i from calendar year 

i¥1. 

(ii) The party subsequently meets the 

requirements of paragraph (a)(1) of this 

section for calendar year i+1 and carries 

no deficit into year i+2. 

(2) A deficit is calculated according to 

the following formula: 

Di RVOi¥1 (∑RINNUM)i∂1

(∑RINNUM)i¥1

Where: 

Di = The deficit, in gallons, generated in 

calendar year i that must be carried over 

to year i+1 if allowed to do so pursuant 

to paragraph (b)(1)(i) of this section. 

RVOi = The Renewable Volume Obligation 

for the obligated party or renewable fuel 

exporter for calendar year i, in gallons. 

(∑RINNUM)i¥1 = Sum of all acquired gallonRINs that were generated in year i and 

are being applied towards the RVOi, in 

gallons. 

(∑RINNUM)i¥1 = Sum of all acquired gallonRINs that were generated in year i¥1 

and are being applied towards the RVOi,

in gallons. 

§ 80.1128 General requirements for RIN 

distribution. 

(a) RINs assigned to volumes of 

renewable fuel. (1) Assigned RIN, for the 

purposes of this subpart, means a RIN 

assigned to a volume of renewable fuel 

pursuant to § 80.1126(e) with a K code 

of 1. 

(2) Except as provided in 

§ 80.1126(e)(4) and § 80.1129, no party 

can separate a RIN that has been 

assigned to a batch pursuant to 

§ 80.1126(e). 

(3) An assigned RIN cannot be 

transferred to another party without 

simultaneously transferring a volume of 

renewable fuel to that same party. 

(4) No more than 2.5 assigned gallonRINs with a K code of 1 can be 

transferred to another party with every 

gallon of renewable fuel transferred to 

that same party. 

(5) (i) On each of the dates listed in 

paragraph (a)(5)(v) of this section in any 

calendar year, the following equation 

must be satisfied for assigned RINs and 

volumes of renewable fuel owned by a 

party: 

∑(RIN)D ≤ ∑(Vsi ×EVi)D

Where: 

D = Applicable date. 

∑(RIN)D = Sum of all assigned gallon-RINs 

with a K code of 1 that are owned on 

date D. 

(Vsi)D = Volume i of renewable fuel owned on 

date D, standardized to 60 °F, in gallons. 

EVi = Equivalence value representing volume 

i. 

∑(Vsi× EVi)D = Sum of all volumes of 

renewable fuel owned on date D, 

multiplied by their respective 

equivalence values. 

(ii) The equivalence value EVi for use 

in the equation in paragraph (a)(5)(i) of 

this section for any volume of ethanol 

shall be 2.5. 

(iii) If the equivalence value for a 

volume of renewable fuel i can be 

determined pursuant to § 80.1115 based 

on its composition, then the appropriate 

equivalence value shall be used for EVi. 

(iv) If the equivalence value for a 

volume of renewable fuel cannot be 

determined based on its composition, 

the value of EVi shall be 1.0. 

(v) The applicable dates are March 31, 

June 30, September 30, and December 

31. For 2007 only, the applicable dates 

are September 30, and December 31. 

(6) Producers and importers of 

renewable fuel. (i) Except as provided in 

paragraph (a)(6)(ii) of this section, a 

producer or importer of renewable fuel 

must transfer ownership of a number of 

gallon-RINs with a K code of 1 

whenever it transfers ownership of a 

volume of renewable fuel such that the 

ratio of gallon-RINs to gallons is equal 

to the equivalence value for the 

renewable fuel. 

∑(RIN) / Vs = EV 

Where: 

∑(RIN) = Sum of all gallon-RINs with a K 

code of 1 which are transferred along 

with volume Vs. 

Vs = A volume of renewable fuel transferred, 

standardized to 60 °F, in gallons. 

EV = Equivalence value assigned to the 

renewable fuel being transferred. 

(ii) A producer or importer of 

renewable fuel can transfer ownership 

of a volume of renewable fuel without 

simultaneously transferring ownership 

of gallon-RINs having a K code of 1 if 

it can demonstrate one of the following: 

(A) It is a small volume producer 

exempt from the requirement to 

generate RINs pursuant to § 80.1126(b); 

or 

(B) The producer or importer received 

an equivalent volume of renewable fuel 

from another party without 

accompanying RINs. 

(C) The producer or importer has 

generated RINs for cellulosic biomass 

ethanol or waste-derived ethanol having 

an equivalence value of 2.5, and has 

chosen to specify as unassigned a 

number of gallon-RINs pursuant to 

§ 80.1126(e)(4). 

(7) Any transfer of ownership of 

assigned RINs must be documented on 

product transfer documents generated 

pursuant to § 80.1153. 

(i) The RIN must be recorded on the 

product transfer document used to 

transfer ownership of the RIN and the 

volume to another party; or 

(ii) The RIN must be recorded on a 

separate product transfer document 

transferred to the same party on the 

same day as the product transfer 

document used to transfer ownership of 

the volume of renewable fuel. 

(b) RINs not assigned to volumes of 

renewable fuel. (1) Unassigned RIN, for 

the purposes of this subpart, means a 

RIN with a K code of 2 that has been 

separated from a volume of renewable 

fuel pursuant to § 80.1126(e)(4) or 

§ 80.1129. 

(2) Any party that has registered 

pursuant to § 80.1150 can hold title to 

an unassigned RIN. 

(3) Unassigned RINs can be 

transferred from one party to another 

any number of times. 


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(4) An unassigned batch-RIN can be 

divided by its holder into multiple 

batch-RINs, each representing a smaller 

number of gallon-RINs, if all of the 

following conditions are met: 

(i) All RIN components other than 

SSSSSSSS and EEEEEEEE are identical 

for the original parent and newly 

formed daughter RINs. 

(ii) The sum of the gallon-RINs 

associated with the multiple daughter 

batch-RINs is equal to the gallon-RINs 

associated with the parent batch-RIN. 

§ 80.1129 Requirements for separating 

RINs from volumes of renewable fuel. 

(a)(1) Separation of a RIN from a 

volume of renewable fuel means 

termination of the assignment of the RIN 

to a volume of renewable fuel. 

(2) RINs that have been separated 

from volumes of renewable fuel become 

unassigned RINs subject to the 

provisions of § 80.1128(b). 

(b) A RIN that is assigned to a volume 

of renewable fuel is separated from that 

volume only under one of the following 

conditions: 

(1) Except as provided in paragraph 

(b)(6) of this section, a party that is an 

obligated party according to § 80.1106 

must separate any RINs that have been 

assigned to a volume of renewable fuel 

if they own that volume. 

(2) Except as provided in paragraph 

(b)(5) of this section, any party that 

owns a volume of renewable fuel must 

separate any RINs that have been 

assigned to that volume once the 

volume is blended with gasoline or 

diesel to produce a motor vehicle fuel. 

(3) Any party that exports a volume of 

renewable fuel must separate any RINs 

that have been assigned to the exported 

volume. 

(4) Any renewable fuel producer or 

importer that produces or imports a 

volume of renewable fuel shall have the 

right to separate any RINs that have 

been assigned to that volume if the 

producer or importer designates the 

renewable fuel as motor vehicle fuel and 

the renewable fuel is used as motor 

vehicle fuel. 

(5) RINs assigned to a volume of 

biodiesel (mono-alkyl ester) can only be 

separated from that volume pursuant to 

paragraph (b)(2) of this section if such 

biodiesel is blended into diesel fuel at 

a concentration of 80 volume percent 

biodiesel (mono-alkyl ester) or less. 

(i) This paragraph (b)(5) shall not 

apply to obligated parties or exporters of 

renewable fuel. 

(ii) This paragraph (b)(5) shall not 

apply to renewable fuel producers 

meeting the requirements of paragraph 

(b)(4) of this section. 

(6) For RINs that an obligated party 

generates, the obligated party can only 

separate such RINs from volumes of 

renewable fuel if the number of gallonRINs separated is less than or equal to 

its annual RVO. 

(7) A producer or importer of 

cellulosic biomass ethanol or wastederived ethanol can separate a portion 

of the RINs that it generates pursuant to 

§ 80.1126(e)(4). 

(c) The party responsible for 

separating a RIN from a volume of 

renewable fuel shall change the K code 

in the RIN from a value of 1 to a value 

of 2 prior to transferring the RIN to any 

other party. 

(d) (1) Upon and after separation from 

a renewable fuel volume, a RIN shall not 

appear on documentation that is either: 

(i) Used to identify title to the volume 

of renewable fuel; or 

(ii) Transferred with the volume of 

renewable fuel. 

(2) Upon and after separation of a RIN 

from its associated volume, product 

transfer documents used to transfer 

ownership of the volume must continue 

to meet the requirements of 

§ 80.1153(a)(5)(iii). 

(e) Any obligated party that uses a 

renewable fuel in a boiler or heater must 

retire any RINs associated with that 

volume of renewable fuel and report the 

retired RINs in the applicable reports 

under § 80.1152. 

§ 80.1130 Requirements for exporters of 

renewable fuels. 

(a) Any party that owns any amount 

of renewable fuel (in its neat form or 

blended with gasoline or diesel) that is 

exported from the region described in 

§ 80.1126(a) shall acquire sufficient 

RINs to offset a Renewable Volume 

Obligation representing the exported 

renewable fuel. 

(b) Renewable Volume Obligations. 

An exporter of renewable fuel shall 

determine its Renewable Volume 

Obligation from the volumes of the 

renewable fuel exported. 

(1) A renewable fuel exporter’s total 

Renewable Volume Obligation shall be 

calculated according to the following 

formula: 

RVOi = S(VOLk * EVk)i + Di-1

Where: 

RVOi = The Renewable Volume Obligation 

for the exporter for calendar year i, in 

gallons of renewable fuel. 

k = A discrete volume of renewable fuel. 

VOLk = The standardized volume of discrete 

volume k of exported renewable fuel, in 

gallons, calculated in accordance with 

§ 80.1126(d)(7). 

EVk = The equivalence value associated with 

discrete volume k. 

S = Sum involving all volumes of renewable 

fuel exported. 

Di-1 = Renewable fuel deficit carryover 

from the previous year, in gallons. 

(2)(i) If the equivalence value for a 

volume of renewable fuel can be 

determined pursuant to § 80.1115 based 

on its composition, then the appropriate 

equivalence value shall be used in the 

calculation of the exporter’s Renewable 

Volume Obligation. 

(ii) If the equivalence value for a 

volume of renewable fuel cannot be 

determined, the value of EVk shall be 

1.0. 

(c) Each exporter of renewable fuel 

must demonstrate compliance with its 

RVO using RINs it has acquired 

pursuant to § 80.1127. 

§ 80.1131 Treatment of invalid RINs. 

(a) Invalid RINs. An invalid RIN is a 

RIN that is any of the following: 

(1) Is a duplicate of a valid RIN. 

(2) Was based on volumes that have 

not been standardized to 60 °F. 

(3) Has expired. 

(4) Was based on an incorrect 

equivalence value. 

(5) Is deemed invalid under 

§ 80.1167(g). 

(6) Does not represent renewable fuel 

as it is defined in § 80.1101. 

(7) Was otherwise improperly 

generated. 

(b) In the case of RINs that are invalid, 

the following provisions apply: 

(1) Invalid RINs cannot be used to 

achieve compliance with the Renewable 

Volume Obligation of an obligated party 

or exporter, regardless of the party’s 

good faith belief that the RINs were 

valid at the time they were acquired. 

(2) Upon determination by any party 

that RINs owned are invalid, the party 

must adjust their records, reports, and 

compliance calculations as necessary to 

reflect the deletion of the invalid RINs. 

(3) Any valid RINs remaining after 

deleting invalid RINs must first be 

applied to correct the transfer of invalid 

RINs to another party before applying 

the valid RINs to meet the party’s 

Renewable Volume Obligation at the 

end of the compliance year. 

(4) In the event that the same RIN is 

transferred to two or more parties, all 

such RINs will be deemed to be invalid, 

unless EPA in its sole discretion 

determines that some portion of these 

RINs is valid. 

§ 80.1132 Reported spillage of renewable 

fuel. 

(a) A reported spillage under 

paragraph (d) of this section means a 

spillage of renewable fuel associated 

with a requirement by a federal, state or 

local authority to report the spillage. 

(b) Except as provided in paragraph 

(c) of this section, in the event of a 

reported spillage of any volume of 

renewable fuel, the owner of the 


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renewable fuel must retire a number of 

gallon-RINs corresponding to the 

volume of spilled renewable fuel 

multiplied by its equivalence value. 

(1) If the equivalence value for the 

spilled volume may be determined 

pursuant to § 80.1115 based on its 

composition, then the appropriate 

equivalence value shall be used. 

(2) If the equivalence value for a 

spilled volume of renewable fuel cannot 

be determined, the equivalence value 

shall be 1.0. 

(c) If the owner of a volume of 

renewable fuel that is spilled and 

reported establishes that no RINs were 

generated to represent the volume, then 

no gallon-RINs shall be retired. 

(d) A RIN that is retired under 

paragraph (b) of this section: 

(1) Must be reported as a retired RIN 

in the applicable reports under 

§ 80.1152. 

(2) May not be transferred to another 

party or used by any obligated party to 

demonstrate compliance with the 

party’s Renewable Volume Obligation. 

§§ 80.1133 through 80.1140 [Reserved] 

■ 10. Sections 80.1133 through 80.1140 

are reserved. 

■ 11. Sections 80.1141 through 80.1143 

are added to read as follows: 

§ 80.1141 Small refinery exemption. 

(a)(1) Gasoline produced at a refinery 

by a refiner, or foreign refiner (as 

defined at § 80.1165(a)), is exempt from 

the renewable fuel standards of 

§ 80.1105 if that refinery meets the 

definition of a small refinery under 

§ 80.1101(g) for calendar year 20460. 

(2) This exemption shall apply 

through December 31, 2010, unless a 

refiner chooses to waive this exemption 

(as described in paragraph (f) of this 

section), or the exemption is extended 

(as described in paragraph (e) of this 

section). 

(3) For the purposes of this section, 

the term ‘‘refiner’’ shall include foreign 

refiners. 

(b)(1) The small refinery exemption is 

effective immediately, except as 

specified in paragraph (b)(4) of this 

section. 

(2) A refiner owning a small refinery 

must submit a verification letter to EPA 

containing all of the following 

information: 

(i) The annual average aggregate daily 

crude oil throughput for the period 

January 1, 2004, through December 31, 

2004 (as determined by dividing the 

aggregate throughput for the calendar 

year by the number 365). 

(ii) A letter signed by the president, 

chief operating or chief executive officer 

of the company, or his/her designee, 

stating that the information contained in 

the letter is true to the best of his/her 

knowledge, and that the company 

owned the refinery as of January 1, 

2004. 

(iii) Name, address, phone number, 

facsimile number, and e-mail address of 

a corporate contact person. 

(3) Verification letters must be 

submitted by August 31, 2007, to one of 

the addresses listed in paragraph (h) of 

this section. 

(4) For foreign refiners the small 

refinery exemption shall be effective 

upon approval, by EPA, of a small 

refinery application. The application 

must contain all of the elements 

required for small refinery verification 

letters (as specified in paragraph (b)(2) 

of this section), must satisfy the 

provisions of § 80.1165(f) through (h) 

and (o), and must be submitted by 

August 31, 2007 to one of the addresses 

listed in paragraph (h) of this section. 

(c) If EPA finds that a refiner provided 

false or inaccurate information 

regarding a refinery’s crude throughput 

(pursuant to paragraph (b)(2)(i) of this 

section) in its small refinery verification 

letter, the exemption will be void as of 

the effective date of these regulations. 

(d) If a refiner is complying on an 

aggregate basis for multiple refineries, 

any such refiner may exclude from the 

calculation of its Renewable Volume 

Obligation (under § 80.1107(a)) gasoline 

from any refinery receiving the small 

refinery exemption under paragraph (a) 

of this section. 

(e)(1) The exemption period in 

paragraph (a) of this section shall be 

extended by the Administrator for a 

period of not less than two additional 

years if a study by the Secretary of 

Energy determines that compliance with 

the requirements of this subpart would 

impose a disproportionate economic 

hardship on the small refinery. 

(i) A refiner may at any time petition 

the Administrator for an extension of its 

small refinery exemption under 

paragraph (a) of this section for the 

reason of disproportionate economic 

hardship. 

(ii) A petition for an extension of the 

small refinery exemption must specify 

the factors that demonstrate a 

disproportionate economic hardship 

and must provide a detailed discussion 

regarding the inability of the refinery to 

produce gasoline meeting the 

requirements of § 80.1105 and the date 

the refiner anticipates that compliance 

with the requirements can be achieved 

at the small refinery. 

(2) The Administrator shall act on 

such a petition not later than 90 days 

after the date of receipt of the petition. 

(f) At any time, a refiner with an 

approved small refinery exemption 

under paragraph (a) of this section may 

waive that exemption upon notification 

to EPA. 

(1) A refiner’s notice to EPA that it 

intends to waive its small refinery 

exemption must be received by 

November 1 to be effective in the next 

compliance year. 

(2) The waiver will be effective 

beginning on January 1 of the following 

calendar year, at which point the 

gasoline produced at that refinery will 

be subject to the renewable fuels 

standard of § 80.1105. 

(3) The waiver must be sent to EPA 

at one of the addresses listed in 

paragraph (h) of this section. 

(g) A refiner that acquires a refinery 

from either an approved small refiner 

(as defined under § 80.1142(a)) or 

another refiner with an approved small 

refinery exemption under paragraph (a) 

of this section shall notify EPA in 

writing no later than 20 days following 

the acquisition. 

(h) Verification letters under 

paragraph (b) of this section, petitions 

for small refinery hardship extensions 

under paragraph (e) of this section, and 

small refinery exemption waivers under 

paragraph (f) of this section shall be sent 

to one of the following addresses: 

(1) For U.S. mail: U.S. EPA—Attn: 

RFS Program, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS Program, 6406J, 

1310 L Street, NW., 6th floor, 

Washington, DC 20005. 

§ 80.1142 What are the provisions for 

small refiners under the RFS program? 

(a) (1) Gasoline produced by a refiner, 

or foreign refiner (as defined at 

§ 80.1165(a)), is exempt from the 

renewable fuel standards of § 80.1105 if 

the refiner or foreign refiner does not 

meet the definition of a small refinery 

under § 80.1101(g) but meets all of the 

following criteria: 

(i) The refiner produced gasoline at its 

refineries by processing crude oil 

through refinery processing units from 

January 1, 2004 through December 31, 

2004. 

(ii) The refiner employed an average 

of no more than 1,500 people, based on 

the average number of employees for all 

pay periods for calendar year 2004 for 

all subsidiary companies, all parent 

companies, all subsidiaries of the parent 

companies, and all joint venture 

partners. 

(iii) The refiner had a corporateaverage crude oil capacity less than or 

equal to 155,000 barrels per calendar 

day (bpcd) for 2004. 


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(2) The small refiner exemption shall 

apply through December 31, 2010, 

unless a refiner chooses to waive the 

exemption (pursuant to paragraph (h) of 

this section) prior to that date. 

(3) For the purposes of this section, 

the term ‘‘refiner’’ shall include foreign 

refiners. 

(b) The small refiner exemption is 

effective immediately, except as 

provided in paragraph (d) of this 

section. Refiners who qualify for the 

small refiner exemption under 

paragraph (a) of this section must 

submit a verification letter (and any 

other relevant information) to EPA 

containing all of the following 

information for the refiner and for all 

subsidiary companies, all parent 

companies, all subsidiaries of the parent 

companies, and all joint venture 

partners: 

(1)(i) A listing of the name and 

address of each company location where 

any employee worked for the period 

January 1, 2004 through December 31, 

2004. 

(ii) The average number of employees 

at each location based on the number of 

employees for each pay period for the 

period January 1, 2004 through 

December 31, 2004. 

(iii) The type of business activities 

carried out at each location. 

(iv) For joint ventures, the total 

number of employees includes the 

combined employee count of all 

corporate entities in the venture. 

(v) For government-owned refiners, 

the total employee count includes all 

government employees. 

(2) The total corporate crude oil 

capacity of each refinery as reported to 

the Energy Information Administration 

(EIA) of the U.S. Department of Energy 

(DOE), for the period January 1, 2004 

through December 31, 2004. The 

information submitted to EIA is 

presumed to be correct. In cases where 

a company disagrees with this 

information, the company may petition 

EPA with appropriate data to correct the 

record when the company submits its 

verification letter. 

(3) The verification letter must be 

signed by the president, chief operating 

or chief executive officer of the 

company, or his/her designee, stating 

that the information is true to the best 

of his/her knowledge, and that the 

company owned the refinery as of 

December 31, 2004. 

(4) Name, address, phone number, 

facsimile number, and e-mail address of 

a corporate contact person. 

(c) Verification letters under 

paragraph (b) of this section must be 

submitted by September 1, 2007. 

(d) For foreign refiners the small 

refiner exemption shall be effective 

upon approval, by EPA, of a small 

refiner application. The application 

must contain all of the elements 

required for small refiner verification 

letters (as specified in paragraphs (b)(1), 

(b)(3), and (b)(4) of this section), must 

demonstrate compliance with the crude 

oil capacity criterion of paragraph 

(a)(1)(iii) of this section, must satisfy the 

provisions of § 80.1165(f) through (h) 

and (o), and must be submitted by 

September 1, 2007 to one of the 

addresses listed in paragraph (j) of this 

section. 

(e) A refiner who qualifies as a small 

refiner under this section and 

subsequently fails to meet all of the 

qualifying criteria as set out in 

paragraph (a) of this section will have 

its small refiner exemption terminated 

effective January 1 of the next calendar 

year; however, disqualification shall not 

apply in the case of a merger between 

two approved small refiners. 

(f) If EPA finds that a refiner provided 

false or inaccurate information in its 

small refiner status verification letter 

under this subpart, the small refiner’s 

exemption will be void as of the 

effective date of these regulations. 

(g) If a small refiner is complying on 

an aggregate basis for multiple 

refineries, the refiner may exempt the 

refineries from the calculation of its 

Renewable Volume Obligation under 

§ 80.1107. 

(h) (1) A refiner may, at any time, 

waive the small refiner exemption 

under paragraph (a) of this section upon 

notification to EPA. 

(2) A refiner’s notice to EPA that it 

intends to waive the small refiner 

exemption must be received by 

November 1 in order for the waiver to 

be effective for the following calendar 

year. The waiver will be effective 

beginning on January 1 of the following 

calendar year, at which point the refiner 

will be subject to the renewable fuel 

standard of § 80.1105. 

(3) The waiver must be sent to EPA 

at one of the addresses listed in 

paragraph (j) of this section. 

(i) Any refiner that acquires a refinery 

from another refiner with approved 

small refiner status under paragraph (a) 

of this section shall notify EPA in 

writing no later than 20 days following 

the acquisition. 

(j) Verification letters under paragraph 

(b) of this section and small refiner 

exemption waivers under paragraph (h) 

of this section shall be sent to one of the 

following addresses: 

(1) For U.S. Mail: U.S. EPA—Attn: 

RFS Program, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS Program, 6406J, 

1310 L Street, NW., 6th floor, 

Washington, DC 20005. 

§ 80.1143 What are the opt-in provisions 

for noncontiguous states and territories? 

(a) A noncontiguous state or United 

States territory may petition the 

Administrator to opt-in to the program 

requirements of this subpart. 

(b) The Administrator will approve 

the petition if it meets the provisions of 

paragraphs (c) and (d) of this section. 

(c) The petition must be signed by the 

Governor of the state or his authorized 

representative (or the equivalent official 

of the territory). 

(d)(1) A petition submitted under this 

section must be received by the Agency 

by November 1 for the state or territory 

to be included in the RFS program in 

the next calendar year. 

(2) A petition submitted under this 

section should be sent to either of the 

following addresses: 

(i) For U.S. Mail: U.S. EPA—Attn: RFS 

Program, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(ii) For overnight or courier services: 

U.S. EPA, Attn: RFS Program, 6406J, 

1310 L Street, NW., 6th floor, 

Washington, DC 20005. 

(e) Upon approval of the petition by 

the Administrator: 

(1) EPA shall calculate the standard 

for the following year, including the 

total gasoline volume for the State or 

territory in question. 

(2) Beginning on January 1 of the next 

calendar year, all gasoline refiners and 

importers in the state or territory for 

which a petition has been approved 

shall be obligated parties as defined in 

§ 80.1106. 

(3) Beginning on January 1 of the next 

calendar year, all renewable fuel 

producers in the State or territory for 

which a petition has been approved 

shall, pursuant to § 80.1126(a)(2), be 

required to generate RINs and assign 

them to batches of renewable fuel. 

§§ 80.1144 through 80.1149 [Reserved] 

■ 12. Sections 80.1144 through 80.1149 

are reserved. 

■ 13. Sections 80.1150 through 80.1155 

are added to read as follows: 

Subpart K—Renewable Fuel Standard 

* * * * * 

Sec. 

80.1150 What are the registration 

requirements under the RFS program? 

80.1151 What are the recordkeeping 

requirements under the RFS program? 

80.1152 What are the reporting 

requirements under the RFS program? 


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80.1153 What are the product transfer 

document (PTD) requirements for the 

RFS program? 

80.1154 What are the provisions for 

renewable fuel producers and importers 

who produce or import less than 10,000 

gallons of renewable fuel per year? 

80.1155 What are the additional 

requirements for a producer of cellulosic 

biomass ethanol or waste derived 

ethanol? 

* * * * * 

§ 80.1150 What are the registration 

requirements under the RFS program? 

(a) Any obligated party described in 

§ 80.1106 and any exporter of renewable 

fuel described in § 80.1130 must 

provide EPA with the information 

specified for registration under § 80.76, 

if such information has not already been 

provided under the provisions of this 

part. An obligated party or an exporter 

of renewable fuel must receive EPAissued identification numbers prior to 

engaging in any transaction involving 

RINs. Registration information may be 

submitted to EPA at any time after 

promulgation of this rule in the Federal 

Register. 

(b) Any importer or producer of a 

renewable fuel must provide EPA the 

information specified under § 80.76, if 

such information has not already been 

provided under the provisions of this 

part, and must receive EPA-issued 

company and facility identification 

numbers prior to generating or assigning 

any RINs. Registration information may 

be submitted to EPA at any time after 

promulgation of this rule in the Federal 

Register. 

(c) Any party who owns or intends to 

own RINs, but who is not covered by 

paragraphs (a) and (b) of this section, 

must provide EPA the information 

specified under § 80.76, if such 

information has not already been 

provided under the provisions of this 

part and must receive an EPA-issued 

company identification number prior to 

owning any RINs. Registration 

information may be submitted to EPA at 

any time after promulgation of this rule 

in the Federal Register. 

(d) Registration shall be on forms, and 

following policies, established by the 

Administrator. 

§ 80.1151 What are the recordkeeping 

requirements under the RFS program? 

(a) Beginning September 1, 2007, any 

obligated party (as described at 

§ 80.1106) or exporter of renewable fuel 

(as described at § 80.1130) must keep all 

of the following records: 

(1) Product transfer documents 

consistent with § 80.1153 and associated 

with the obligated party’s activity, if 

any, as transferor or transferee of 

renewable fuel. 

(2) Copies of all reports submitted to 

EPA under § 80.1152(a). 

(3) Records related to each RIN 

transaction, which includes all the 

following: 

(i) A list of the RINs owned, 

purchased, sold, retired or expired. 

(ii) The parties involved in each RIN 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The date of the transfer of the 

RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(4) Records related to the use of RINs 

(by facility, if applicable) for 

compliance, which includes all the 

following: 

(i) Methods and variables used to 

calculate the Renewable Volume 

Obligation pursuant to § 80.1107 or 

§ 80.1130. 

(ii) List of RINs used to demonstrate 

compliance. 

(iii) Additional information related to 

details of RIN use for compliance. 

(b) Beginning September 1, 2007, any 

producer or importer of a renewable fuel 

as defined at § 80.1101(d) must keep all 

of the following records: 

(1) Product transfer documents 

consistent with § 80.1153 and associated 

with the renewable fuel producer’s or 

importer’s activity, if any, as transferor 

or transferee of renewable fuel. 

(2) Copies of all reports submitted to 

EPA under § 80.1152(b). 

(3) Records related to the generation 

and assignment of RINs for each facility, 

including all of the following: 

(i) Batch volume in gallons. 

(ii) Batch number. 

(iii) RIN number as assigned under 

§ 80.1126. 

(iv) Identification of batches meeting 

the definition of cellulosic biomass 

ethanol. 

(v) Date of production or import. 

(vi) Results of any laboratory analysis 

of batch chemical composition or 

physical properties. 

(vii) Additional information related to 

details of RIN generation. 

(4) Records related to each RIN 

transaction, including all of the 

following: 

(i) A list of the RINs owned, 

purchased, sold, retired or expired. 

(ii) The parties involved in each 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The date of the transfer of the 

RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(5) Records related to the production 

or importation of any volume of 

renewable fuel that the renewable fuel 

producer or importer designates as 

motor vehicle fuel and the use of the 

fuel as motor vehicle fuel. 

(c) Beginning September 1, 2007, any 

producer of a renewable fuel defined at 

§ 80.1101(d) must keep verifiable 

records of the following: 

(1) The amount and type of fossil fuel 

and waste material-derived fuel used in 

producing on-site thermal energy 

dedicated to the production of ethanol 

at plants producing cellulosic biomass 

ethanol through the displacement of 90 

percent or more of the fossil fuel 

normally used in the production of 

ethanol, as described at § 80.1101(a)(2). 

(2) The amount and type of feedstocks 

used in producing cellulosic biomass 

ethanol as defined in § 80.1101(a)(1). 

(3) The equivalent amount of fossil 

fuel (based on reasonable estimates) 

associated with the use of off-site 

generated waste heat that is used in the 

production of ethanol at plants 

producing cellulosic biomass ethanol 

through the displacement of 90 percent 

or more of the fossil fuel normally used 

in the production of ethanol, as 

described at § 80.1101(a)(2). 

(4) The plot plan and process flow 

diagram for plants producing cellulosic 

biomass and waste derived ethanol as 

defined in § 80.1101(a) and (b), 

respectively. 

(5) The independent third party 

verification required under § 80.1155 for 

producers of cellulosic biomass ethanol 

and waste derived ethanol. 

(d) Beginning September 1, 2007, any 

party, other than those parties covered 

in paragraphs (a) and (b) of this section, 

that owns RINs must keep all of the 

following records: 

(1) Product transfer documents 

consistent with § 80.1153 and associated 

with the party’s activity, if any, as 

transferor or transferee of renewable 

fuel. 

(2) Copies of all reports submitted to 

EPA under § 80.1152(c). 

(3) Records related to each RIN 

transaction, including all of the 

following: 

(i) A list of the RINs owned, 

purchased, sold, retired or expired. 

(ii) The parties involved in each RIN 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The date of the transfer of the 

RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(e) The records required under this 

section and under § 80.1153 shall be 

kept for five years from the date they 

were created, except that records related 

to transactions involving RINs shall be 


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kept for five years from the date of 

transfer. 

(f) On request by EPA, the records 

required under this section and under 

§ 80.1153 must be made available to the 

Administrator or the Administrator’s 

authorized representative. For records 

that are electronically generated or 

maintained, the equipment or software 

necessary to read the records shall be 

made available; or, if requested by EPA, 

electronic records shall be converted to 

paper documents. 

§ 80.1152 What are the reporting 

requirements under the RFS program? 

(a) Any obligated party described in 

§ 80.1106 or exporter of renewable fuel 

described in § 80.1130 must submit to 

EPA reports according to the schedule, 

and containing the information, that is 

set forth in this paragraph (a). 

(1) An annual compliance 

demonstration report for the previous 

compliance period shall be submitted 

every February 28, except as noted in 

paragraph (a)(1)(x) of this section, and 

shall include all of the following 

information: 

(i) The obligated party’s name. 

(ii) The EPA company registration 

number. 

(iii) Whether the party is complying 

on a corporate (aggregate) or facility-byfacility basis. 

(iv) The EPA facility registration 

number, if complying on a facility-byfacility basis. 

(v) The production volume of all of 

the products listed in § 80.1107(c) for 

the reporting year. 

(vi) The renewable volume obligation 

(RVO), as defined in § 80.1127(a) for 

obligated parties and § 80.1130(b) for 

exporters of renewable fuel, for the 

reporting year. 

(vii) Any deficit RVO carried over 

from the previous year. 

(viii) The total current-year gallonRINs used for compliance. 

(ix) The total prior-years gallon-RINs 

used for compliance. 

(x) A list of all RINs used for 

compliance in the reporting year. For 

compliance demonstrations covering 

calendar year 2007 only, this list shall 

be reported by May 31, 2008. In all 

subsequent years, this list shall be 

submitted by February 28. 

(xi) Any deficit RVO carried into the 

subsequent year. 

(xii) Any additional information that 

the Administrator may require. 

(2) The quarterly RIN transaction 

reports required under paragraph (c)(1) 

of this section. 

(3) The quarterly gallon-RIN activity 

reports required under paragraph (c)(2) 

of this section. 

(4) Reports required under this 

paragraph (a) must be signed and 

certified as meeting all the applicable 

requirements of this subpart by the 

owner or a responsible corporate officer 

of the obligated party. 

(b) Any producer or importer of a 

renewable fuel must, beginning 

November 30, 2007, submit to EPA 

reports according to the schedule, and 

containing the information, that is set 

forth in this paragraph (b). 

(1) A quarterly RIN-generation report 

for each facility owned by the renewable 

fuel producer, and each importer, shall 

be submitted according to the schedule 

specified in paragraph (d) of this 

section, and shall include for the 

reporting period all of the following 

information for each batch of renewable 

fuel produced or imported, where 

‘‘batch’’ means a discreet quantity of 

renewable fuel produced or imported 

and assigned a unique RIN: 

(i) The renewable fuel producer’s or 

importer’s name. 

(ii) The EPA company registration 

number. 

(iii) The EPA facility registration 

number. 

(iv) The applicable quarterly reporting 

period. 

(v) The RINs generated for each batch 

according to § 80.1126. 

(vi) The production date of each 

batch. 

(vii) The type of renewable fuel of 

each batch, as defined in § 80.1101(d). 

(viii) Information related to the 

volume of denaturant and applicable 

equivalence value of each batch. 

(ix) The volume of each batch 

produced or imported. 

(x) Any additional information the 

Administrator may require. 

(2) The RIN transaction reports 

required under paragraph (c)(1) of this 

section. 

(3) The quarterly gallon-RIN activity 

report required under paragraph (c)(2) of 

this section. 

(4) Reports required under this 

paragraph (b) must be signed and 

certified as meeting all the applicable 

requirements of this subpart by the 

owner or a responsible corporate officer 

of the renewable fuel producer. 

(c) Any party, including any party 

specified in paragraphs (a) and (b) of 

this section, that owns RINs during a 

reporting period must, beginning 

November 30, 2007, submit reports to 

EPA according to the schedule, and 

containing the information, that is set 

forth in this paragraph (c). 

(1) A RIN transaction report for each 

RIN transaction shall be submitted by 

the end of the quarter in which the 

transaction occurred, according to the 

schedule specified in paragraph (d) of 

this section. Each report shall include 

all of the following: 

(i) The submitting party’s name. 

(ii) The party’s EPA company 

registration number. 

(iii) The party’s facility registration 

number, if the report required under 

paragraph (c)(2) of this section is 

submitted on a facility-by-facility basis. 

(iv) The applicable quarterly reporting 

period. 

(v) Transaction type (RIN purchase, 

RIN sale, expired RIN, retired RIN). 

(vi) Transaction date. 

(vii) For a RIN purchase or sale, the 

trading partner’s name. 

(viii) For a RIN purchase or sale, the 

trading partner’s EPA company 

registration number. For all other 

transactions, the submitting party’s EPA 

company registration number. 

(ix) RIN subject to the transaction. 

(x) For a retired RIN, the reason for 

retiring the RIN (e.g., reportable spill 

under § 80.1132, import volume 

correction under § 80.1166(k), 

renewable fuel used in boiler or heater 

under § 80.1129(e), enforcement 

obligation). 

(xi) Any additional information that 

the Administrator may require. 

(2) A quarterly gallon-RIN activity 

report shall be submitted to EPA 

according to the schedule specified in 

paragraph (d) of this section. Each 

report shall summarize gallon-RIN 

activities for the reporting period, 

separately for RINs separated from a 

renewable fuel volume and RINs 

assigned to a renewable fuel volume. A 

RIN owner with more than one facility 

may submit the report required under 

this paragraph for each of its facilities 

individually, or for all of its facilities in 

the aggregate. The quarterly gallon-RIN 

activity report shall include all of the 

following information: 

(i) The submitting party’s name. 

(ii) The party’s EPA company 

registration number. 

(iii) Whether the party is submitting 

the report required under this paragraph 

on a corporate (aggregate) or facility-byfacility basis. 

(iv) The party’s EPA facility 

registration number, if the report 

required under this paragraph is 

submitted on a facility-by-facility basis. 

(v) Number of current-year gallonRINs owned at the start of the quarter. 

(vi) Number of prior-years gallon-RINs 

owned at the start of the quarter. 

(vii) The total current-year gallonRINs purchased. 

(viii) The total prior-years gallon-RINs 

purchased. 

(ix) The total current-year gallon-RINs 

sold. 


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(x) The total prior-years gallon-RINs 

sold. 

(xi) The total current-year gallon-RINs 

retired. 

(xii) The total prior-years gallon-RINs 

retired. 

(xiii) The total current-year gallonRINs expired (fourth quarter only). 

(xiv) The total prior-years gallon-RINs 

expired (fourth quarter only). 

(xv) Number of current-year gallonRINs owned at the end of the quarter. 

(xvi) Number of prior-years gallonRINs owned at the end of the quarter. 

(xvii) For parties reporting gallon-RIN 

activity under this paragraph for RINs 

assigned to a volume of renewable fuel, 

the volume of renewable fuel (in 

gallons) owned at the end of the quarter. 

(xviii) Any additional information 

that the Administrator may require. 

(3) All reports required under this 

paragraph (c) must be signed and 

certified as meeting all the applicable 

requirements of this subpart by the RIN 

owner or a responsible corporate officer 

of the RIN owner. 

(d) Quarterly reports shall be 

submitted to EPA by: May 31st for the 

first calendar quarter of January through 

March; August 31st for the second 

calendar quarter of April through June; 

November 30th for the third calendar 

quarter of July through September; and 

February 28th for the fourth calendar 

quarter of October through December. 

For 2007, quarterly reports shall 

commence on November 30, 2007. 

(e) Reports required under this section 

shall be submitted on forms and 

following procedures as prescribed by 

EPA. 

§ 80.1153 What are the product transfer 

document (PTD) requirements for the RFS 

program? 

(a) Any time that a person transfers 

ownership of renewable fuels subject to 

this subpart, the transferor must provide 

to the transferee documents identifying 

the renewable fuel and any assigned 

RINs which include all of the following 

information as applicable: 

(1) The name and address of the 

transferor and transferee. 

(2) The transferor’s and transferee’s 

EPA company registration number. 

(3) The volume of renewable fuel that 

is being transferred. 

(4) The date of the transfer. 

(5) Whether any RINs are assigned to 

the volume, as follows: 

(i) If the assigned RINs are being 

transferred on the same PTD used to 

transfer ownership of the renewable 

fuel, then the assigned RINs shall be 

listed on the PTD. 

(ii) If the assigned RINs are being 

transferred on a separate PTD from that 

which is used to transfer ownership of 

the renewable fuel, then the PTD which 

is used to transfer ownership of the 

renewable fuel shall state the number of 

gallon-RINs being transferred as well as 

a unique reference to the PTD which is 

transferring the assigned RINs. 

(iii) If no assigned RINs are being 

transferred with the renewable fuel, the 

PTD which is used to transfer 

ownership of the renewable fuel shall 

state ‘‘No RINs transferred’’. 

(b) Except for transfers to truck 

carriers, retailers, or wholesale 

purchaser-consumers, product codes 

may be used to convey the information 

required under paragraphs (a)(1) 

through (a)(4) of this section if such 

codes are clearly understood by each 

transferee. The RIN number required 

under paragraph (a)(5) of this section 

must always appear in its entirety. 

§ 80.1154 What are the provisions for 

renewable fuel producers and importers 

who produce or import less than 10,000 

gallons of renewable fuel per year? 

(a) Renewable fuel producers located 

within the United States that produce 

less than 10,000 gallons of renewable 

fuel each year, and importers who 

import less than 10,000 gallons of 

renewable fuel each year, are not 

required to generate RINs or to assign 

RINs to batches of renewable fuel. Such 

producers and importers that do not 

generate and/or assign RINs to batches 

of renewable fuel are also exempt from 

all the following requirements of this 

subpart K, except as stated in paragraph 

(b) of this section: 

(1) The registration requirements of 

§ 80.1150. 

(2) The recordkeeping requirements of 

§ 80.1151. 

(3) The reporting requirements of 

§ 80.1152. 

(b) Renewable fuel producers and 

importers who produce or import less 

than 10,000 gallons of renewable fuel 

each year and that generate and/or 

assign RINs to batches of renewable fuel 

are subject to the provisions of 

§§ 80.1150 through 80.1152. 

§ 80.1155 What are the additional 

requirements for a producer of cellulosic 

biomass ethanol or waste derived ethanol? 

(a) A producer of cellulosic biomass 

ethanol or waste derived ethanol 

(hereinafter referred to as ‘‘ethanol 

producer’’ under this section) is 

required to arrange for an independent 

third party to review the records 

required in § 80.1151(c) and provide the 

ethanol producer with a written 

verification that the records support a 

claim that: 

(1) The ethanol producer’s facility is 

a facility that has the capability of 

producing cellulosic biomass ethanol as 

defined in § 80.1101(a) or waste derived 

ethanol as defined in § 80.1101(b); and 

(2) The ethanol producer produces 

cellulosic biomass ethanol as defined in 

§ 80.1101(a) or waste derived ethanol as 

defined in § 80.1101(b). 

(b) The verifications required under 

paragraph (a) of this section must be 

conducted by a Professional Chemical 

Engineer who is based in the United 

States and is licensed by the appropriate 

state agency, unless the ethanol 

producer is a foreign producer subject to 

§ 80.1166. 

(c) To be considered an independent 

third party under paragraph (a) of this 

section: 

(1) The third party shall not be 

operated by the ethanol producer or any 

subsidiary of employee of the ethanol 

producer. 

(2) The third party shall be free from 

any interest in the ethanol producer’s 

business. 

(3) The ethanol producer shall be free 

from any interest in the third party’s 

business. 

(4) Use of a third party that is 

debarred, suspended, or proposed for 

debarment pursuant to the Governmentwide Debarment and Suspension 

regulations, 40 CFR part 32, or the 

Debarment, Suspension and Ineligibility 

provisions of the Federal Acquisition 

Regulations, 48 CFR, part 9, subpart 9.4, 

shall be deemed noncompliance with 

the requirements of this section. 

(d) The ethanol producer must obtain 

the written verification required under 

paragraph (a)(1) of this section by 

February 28 of the year following the 

first year in which the ethanol producer 

claims to be producing cellulosic 

biomass ethanol or waste derived 

ethanol. 

(e) The verification in paragraph (a)(2) 

of this section is required for each 

calendar year that the ethanol producer 

claims to be producing cellulosic 

biomass ethanol or waste derived 

ethanol. The ethanol producer must 

obtain the written verification required 

under paragraph (a)(2) of this section by 

February 28 for the previous calendar 

year. 

(f) The ethanol producer must retain 

records of the verifications required 

under paragraph (a) of this section, as 

required in § 80.1151(c)(5). 

(g) The independent third party shall 

retain all records pertaining to the 

verification required under this section 

for a period of five years from the date 

of creation and shall deliver such 

records to the Administrator upon 

request. 


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§§ 80.1156 through 80.1159 [Reserved] 

■ 14. Sections 80.1156 through 80.1159 

are reserved. 

■ 15. Sections 80.1160 and 80.1161 are 

added to read as follows: 

§ 80.1160 What acts are prohibited under 

the RFS program? 

(a) Renewable fuels producer or 

importer violation. Except as provided 

in § 80.1154, no person shall produce or 

import a renewable fuel without 

assigning the proper RIN value or 

identifying it by a RIN number as 

required under § 80.1126. 

(b) RIN generation and transfer 

violations. No person shall do any of the 

following: 

(1) Improperly generate a RIN (i.e., 

generate a RIN for which the applicable 

renewable fuel volume was not 

produced). 

(2) Create or transfer to any person a 

RIN that is invalid under § 80.1131. 

(3) Transfer to any person a RIN that 

is not properly identified as required 

under § 80.1125. 

(4) Transfer to any person a RIN with 

a K code of 1 without transferring an 

appropriate volume of renewable fuel to 

the same person on the same day. 

(c) RIN use violations. No person shall 

do any of the following: 

(1) Fail to acquire sufficient RINs, or 

use invalid RINs, to meet the party’s 

renewable fuel volume obligation under 

§ 80.1127. 

(2) Fail to acquire sufficient RINs to 

meet the party’s renewable fuel volume 

obligation under § 80.1130. 

(3) Use a validly generated RIN to 

meet the party’s renewable fuel volume 

obligation under § 80.1127, or separate 

and transfer a validly generated RIN, 

where the party ultimately uses the 

renewable fuel volume associated with 

the RIN in a heater or boiler. 

(d) RIN retention violation. No person 

shall retain RINs in violation of the 

requirements in § 80.1128(a)(5). 

(e) Causing a violation. No person 

shall cause another person to commit an 

act in violation of any prohibited act 

under this section. 

§ 80.1161 Who is liable for violations 

under the RFS program? 

(a) Persons liable for violations of 

prohibited acts. (1) Any person who 

violates a prohibition under § 80.1160(a) 

through (d) is liable for the violation of 

that prohibition. 

(2) Any person who causes another 

person to violate a prohibition under 

§ 80.1160(a) through (d) is liable for a 

violation of § 80.1160(e). 

(b) Persons liable for failure to meet 

other provisions of this subpart. (1) Any 

person who fails to meet a requirement 

of any provision of this subpart is liable 

for a violation of that provision. 

(2) Any person who causes another 

person to fail to meet a requirement of 

any provision of this subpart is liable for 

causing a violation of that provision. 

(c) Parent corporation liability. Any 

parent corporation is liable for any 

violation of this subpart that is 

committed by any of its subsidiaries. 

(d) Joint venture liability. Each partner 

to a joint venture is jointly and severally 

liable for any violation of this subpart 

that is committed by the joint venture 

operation. 

§ 80.1162 [Reserved] 

■ 16. Section 80.1162 is reserved. 

■ 17. Sections 80.1163 through 80.1167 

are added to read as follows: 

Subpart K—Renewable Fuel Standard 

* * * * * 

Sec. 

80.1163 What penalties apply under the 

RFS program? 

80.1164 What are the attest engagement 

requirements under the RFS program? 

80.1165 What are the additional 

requirements under this Subpart for a 

foreign small refiner? 

80.1166 What are the additional 

requirements under this subpart for a 

foreign producer of cellulosic biomass 

ethanol or waste derived ethanol? 

80.1167 What are the additional 

requirements under this subpart for a 

foreign RIN owner? 

* * * * * 

§ 80.1163 What penalties apply under the 

RFS program? 

(a) Any person who is liable for a 

violation under § 80.1161 is subject to a 

civil penalty of up to $32,500, as 

specified in sections 205 and 211(d) of 

the Clean Air Act, for every day of each 

such violation and the amount of 

economic benefit or savings resulting 

from each violation. 

(b) Any person liable under 

§ 80.1161(a) for a violation of 

§ 80.1160(c) for failure to meet a 

renewable volume obligation, or 

§ 80.1160(e) for causing another party to 

fail to meet a renewable volume 

obligation, during any averaging period, 

is subject to a separate day of violation 

for each day in the averaging period. 

(c) Any person liable under 

§ 80.1161(b) for failure to meet, or 

causing a failure to meet, a requirement 

of any provision of this subpart is liable 

for a separate day of violation for each 

day such a requirement remains 

unfulfilled. 

§ 80.1164 What are the attest engagement 

requirements under the RFS program? 

The requirements regarding annual 

attest engagements in §§ 80.125 through 

80.127, and 80.130, also apply to any 

attest engagement procedures required 

under this subpart. In addition to any 

other applicable attest engagement 

procedures, the following annual attest 

engagement procedures are required 

under this subpart. 

(a) The following attest procedures 

shall be completed for any obligated 

party as stated in § 80.1106(a) or 

exporter of renewable fuel that is subject 

to the renewable fuel standard under 

§ 80.1105: 

(1) Annual compliance demonstration 

report. (i) Obtain and read a copy of the 

annual compliance demonstration 

report required under § 80.1152(a)(1) 

which contains information regarding 

all the following: 

(A) The obligated party’s volume of 

finished gasoline, reformulated gasoline 

blendstock for oxygenate blending 

(RBOB), and conventional gasoline 

blendstock that becomes finished 

conventional gasoline upon the addition 

of oxygenate (CBOB) produced or 

imported during the reporting year. 

(B) Renewable volume obligation 

(RVO). 

(C) RINs used for compliance. 

(ii) Obtain documentation of any 

volumes of renewable fuel used in 

gasoline during the reporting year; 

compute and report as a finding the 

volumes of renewable fuel represented 

in these documents. 

(iii) Compare the volumes of gasoline 

reported to EPA in the report required 

under § 80.1152(a)(1) with the volumes, 

excluding any renewable fuel volumes, 

contained in the inventory 

reconciliation analysis under § 80.133. 

(iii) Verify that the production volume 

information in the obligated party’s 

annual summary report required under 

§ 80.1152(a)(1) agrees with the volume 

information, excluding any renewable 

fuel volumes, contained in the 

inventory reconciliation analysis under 

§ 80.133. 

(iv) Compute and report as a finding 

the obligated party’s RVO, and any 

deficit RVO carried over from the 

previous year or carried into the 

subsequent year, and verify that the 

values agree with the values reported to 

EPA. 

(v) Obtain documentation for all RINs 

used for compliance during the year 

being reviewed; compute and report as 

a finding the RIN numbers and year of 

generation of RINs represented in these 

documents; and state whether this 

information agrees with the report to 

EPA. 


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(2) RIN transaction reports. (i) Obtain 

and read copies of a representative 

sample of all RIN transaction reports 

required under § 80.1152(a)(2) for the 

compliance year. 

(ii) Obtain contracts or other 

documents for the representative sample 

of RIN transactions; compute and report 

as a finding the transaction types, 

transaction dates, and RINs traded; and 

state whether the information agrees 

with the party’s reports to EPA. 

(3) Gallon-RIN activity reports. (i) 

Obtain and read copies of all quarterly 

gallon-RIN activity reports required 

under § 80.1152(a)(3) for the compliance 

year. 

(ii) Obtain documentation of total 

RINs (including current-year RINs and 

previous-year RINs) owned at the start 

of the quarter, purchased, used for 

compliance, sold, expired and retired 

during the quarter being reviewed, and 

owned at the end of the quarter; 

compute and report as a finding the 

total RINs owned at the start and end of 

the quarter, purchased, used for 

compliance, sold, expired and retired as 

represented in these documents; and 

state whether this information agrees 

with the party’s reports to EPA. 

(b) The following attest procedures 

shall be completed for any renewable 

fuel producer or importer: 

(1) RIN-generation reports. (i) Obtain 

and read copies of the quarterly RIN 

generation reports required under 

§ 80.1152(b)(1) for the compliance year. 

(ii) Obtain production data for each 

renewable fuel batch produced during 

the year being reviewed; compute and 

report as a finding the RIN numbers, 

production dates, types, volumes of 

denaturant and applicable equivalence 

values, and production volumes for 

each batch; and state whether this 

information agrees with the party’s 

reports to EPA. 

(iii) Verify that the proper number of 

RINs were generated and assigned for 

each batch of renewable fuel produced, 

as required under § 80.1126. 

(iv) Obtain product transfer 

documents for each renewable fuel 

batch produced during the year being 

reviewed; report as a finding any 

product transfer document that did not 

include the RIN for the batch. 

(2) RIN transaction reports. (i) Obtain 

and read copies of a representative 

sample of the RIN transaction reports 

required under § 80.1152(b)(2) for the 

compliance year. 

(ii) Obtain contracts or other 

documents for the representative sample 

of RIN transactions; compute and report 

as a finding the transaction types, 

transaction dates, and the RINs traded; 

and state whether this information 

agrees with the party’s reports to EPA. 

(3) Gallon-RIN activity reports. (i) 

Obtain and read copies of the quarterly 

gallon-RIN activity reports required 

under § 80.1152(b)(3) for the compliance 

year. 

(ii) Obtain documentation of total 

RINs (including current-year RINs and 

previous-year RINs) owned at the start 

of the quarter, purchased, sold, expired 

and retired during the quarter being 

reviewed, and owned at the end of the 

quarter; compute and report as a finding 

the total RINs owned at the start and 

end of the quarter, purchased, used for 

compliance, sold, expired and retired as 

represented in these documents; and 

state whether this information agrees 

with the party’s reports to EPA. 

(c) The following attest procedures 

shall be completed for any party other 

than an obligated party or renewable 

fuel producer or importer that owns any 

RINs during a calendar year. 

(1) RIN transaction reports. (i) Obtain 

and read copies of a representative 

sample of the RIN transaction reports 

required under § 80.1152(c)(1) for the 

compliance year. 

(ii) Obtain contracts or other 

documents for the representative sample 

of RIN transactions; compute and report 

as a finding the transaction types, 

transaction dates, and the RINs traded; 

and state whether this information 

agrees with the party’s reports to EPA. 

(2) Gallon-RIN activity reports. (i) 

Obtain and read copies of the gallonRIN activity reports required under 

§ 80.1152(c)(2) for the compliance year. 

(ii) Obtain documentation of total 

RINs (including current-year RINs and 

previous-year RINs) owned at the start 

of the quarter, purchased, sold, expired 

and retired during the quarter being 

reviewed, and owned at the end of the 

quarter; compute and report as a finding 

the total RINs owned at the start and 

end of the quarter, purchased, used for 

compliance, sold, expired and retired as 

represented in these documents; and 

state whether this information agrees 

with the party’s reports to EPA. 

(d) The following submission dates 

apply to the attest engagements required 

under this section. 

(1) For each compliance year, each 

party subject to the attest engagement 

requirements under this section shall 

cause the reports required under this 

section to be submitted to EPA by May 

31 of the year following the compliance 

year. 

(2) For the 2007 compliance year 

only, the attest engagement required 

under paragraph (a) of this section may 

be submitted to EPA with the attest 

engagement for the 2008 compliance 

year. 

§ 80.1165 What are the additional 

requirements under this subpart for a 

foreign small refiner? 

(a) Definitions. The following 

definitions apply for this subpart: 

(1) Foreign refinery is a refinery that 

is located outside the United States, the 

Commonwealth of Puerto Rico, the U.S. 

Virgin Islands, Guam, American Samoa, 

and the Commonwealth of the Northern 

Mariana Islands (collectively referred to 

in this section as ‘‘the United States’’). 

(2) Foreign refiner is a person that 

meets the definition of refiner under 

§ 80.2(i) for a foreign refinery. 

(3) RFS–FRGAS is gasoline produced 

at a foreign refinery that has received a 

small refinery exemption under 

§ 80.1141 or a small refiner exemption 

under § 80.1142 that is imported into 

the United States. 

(4) Non-RFS–FRGAS is one of the 

following: 

(i) Gasoline produced at a foreign 

refinery that has received a small 

refinery exemption under § 80.1141 or a 

small refiner exemption under § 80.1142 

that is not imported into the United 

States. 

(ii) Gasoline produced at a foreign 

refinery that has not received a small 

refinery exemption under § 80.1141 or 

small refiner exemption under 

§ 80.1142. 

(5) A foreign small refiner is a foreign 

refiner that has received a small refinery 

exemption under § 80.1141 for one or 

more of its refineries or a small refiner 

exemption under § 80.1142. 

(b) General requirements for RFS– 

FRGAS foreign small refineries and 

small refiners. 

(1) A foreign small refiner must 

designate, at the time of production, 

each batch of gasoline produced at the 

foreign refinery that is exported for use 

in the United States as RFS–FRGAS; 

and 

(2) Meet all requirements that apply to 

refiners who have received a small 

refinery or small refiner exemption 

under this subpart. 

(c) Designation, foreign refiner 

certification, and product transfer 

documents. (1) Any foreign small refiner 

must designate each batch of RFS– 

FRGAS as such at the time the gasoline 

is produced. 

(2) On each occasion when RFS– 

FRGAS is loaded onto a vessel or other 

transportation mode for transport to the 

United States, the foreign refiner shall 

prepare a certification for each batch of 

RFS–FRGAS that meets all the following 

requirements: 

(i) The certification shall include the 

report of the independent third party 


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under paragraph (d) of this section, and 

all the following additional information: 

(A) The name and EPA registration 

number of the refinery that produced 

the RFS–FRGAS. 

(B) [Reserved] 

(ii) The identification of the gasoline 

as RFS–FRGAS. 

(iii) The volume of RFS–FRGAS being 

transported, in gallons. 

(3) On each occasion when any 

person transfers custody or title to any 

RFS–FRGAS prior to its being imported 

into the United States, it must include 

all the following information as part of 

the product transfer document 

information: 

(i) Designation of the gasoline as RFS– 

FRGAS. 

(ii) The certification required under 

paragraph (c)(2) of this section. 

(d) Load port independent testing and 

refinery identification. (1) On each 

occasion that RFS–FRGAS is loaded 

onto a vessel for transport to the United 

States the foreign small refiner shall 

have an independent third party do all 

the following: 

(i) Inspect the vessel prior to loading 

and determine the volume of any tank 

bottoms. 

(ii) Determine the volume of RFS– 

FRGAS loaded onto the vessel 

(exclusive of any tank bottoms before 

loading). 

(iii) Obtain the EPA-assigned 

registration number of the foreign 

refinery. 

(iv) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRGAS to the United 

States. 

(v) Determine the date and time the 

vessel departs the port serving the 

foreign refinery. 

(vi) Review original documents that 

reflect movement and storage of the 

RFS–FRGAS from the foreign refinery to 

the load port, and from this review 

determine: 

(A) The refinery at which the RFS– 

FRGAS was produced; and 

(B) That the RFS–FRGAS remained 

segregated from Non-RFS–FRGAS and 

other RFS–FRGAS produced at a 

different refinery. 

(2) The independent third party shall 

submit a report to: 

(i) The foreign small refiner 

containing the information required 

under paragraph (d)(1) of this section, to 

accompany the product transfer 

documents for the vessel; and 

(ii) The Administrator containing the 

information required under paragraph 

(d)(1) of this section, within thirty days 

following the date of the independent 

third party’s inspection. This report 

shall include a description of the 

method used to determine the identity 

of the refinery at which the gasoline was 

produced, assurance that the gasoline 

remained segregated as specified in 

paragraph (j)(1) of this section, and a 

description of the gasoline’s movement 

and storage between production at the 

source refinery and vessel loading. 

(3) The independent third party must: 

(i) Be approved in advance by EPA, 

based on a demonstration of ability to 

perform the procedures required in this 

paragraph (d); 

(ii) Be independent under the criteria 

specified in § 80.65(f)(2)(iii); and 

(iii) Sign a commitment that contains 

the provisions specified in paragraph (f) 

of this section with regard to activities, 

facilities, and documents relevant to 

compliance with the requirements of 

this paragraph (d). 

(e) Comparison of load port and port 

of entry testing. (1)(i) Any small foreign 

small refiner and any United States 

importer of RFS–FRGAS shall compare 

the results from the load port testing 

under paragraph (d) of this section, with 

the port of entry testing as reported 

under paragraph (k) of this section, for 

the volume of gasoline, except as 

specified in paragraph (e)(1)(ii) of this 

section. 

(ii) Where a vessel transporting RFS– 

FRGAS off loads this gasoline at more 

than one United States port of entry, the 

requirements of paragraph (e)(1)(i) of 

this section do not apply at subsequent 

ports of entry if the United States 

importer obtains a certification from the 

vessel owner that the requirements of 

paragraph (e)(1)(i) of this section were 

met and that the vessel has not loaded 

any gasoline or blendstock between the 

first United States port of entry and the 

subsequent port of entry. 

(2) If the temperature-corrected 

volumes determined at the port of entry 

and at the load port differ by more than 

one percent, the United States importer 

and the foreign small refiner shall not 

treat the gasoline as RFS–FRGAS and 

the importer shall include the volume of 

gasoline in the importer’s RFS 

compliance calculations. 

(f) Foreign refiner commitments. Any 

small foreign small refiner shall commit 

to and comply with the provisions 

contained in this paragraph (f) as a 

condition to being approved for a small 

refinery or small refiner exemption 

under this subpart. 

(1) Any United States Environmental 

Protection Agency inspector or auditor 

must be given full, complete and 

immediate access to conduct 

inspections and audits of the foreign 

refinery. 

(i) Inspections and audits may be 

either announced in advance by EPA, or 

unannounced. 

(ii) Access will be provided to any 

location where: 

(A) Gasoline is produced; 

(B) Documents related to refinery 

operations are kept; and 

(C) RFS–FRGAS is stored or 

transported between the foreign refinery 

and the United States, including storage 

tanks, vessels and pipelines. 

(iii) Inspections and audits may be by 

EPA employees or contractors to EPA. 

(iv) Any documents requested that are 

related to matters covered by 

inspections and audits must be 

provided to an EPA inspector or auditor 

on request. 

(v) Inspections and audits by EPA 

may include review and copying of any 

documents related to all the following: 

(A) The volume of RFS–FRGAS. 

(B) The proper classification of 

gasoline as being RFS–FRGAS or as not 

being RFS–FRGAS. 

(C) Transfers of title or custody to 

RFS–FRGAS. 

(D) Testing of RFS–FRGAS. 

(E) Work performed and reports 

prepared by independent third parties 

and by independent auditors under the 

requirements of this section, including 

work papers. 

(vi) Inspections and audits by EPA 

may include taking interviewing 

employees. 

(vii) Any employee of the foreign 

refiner must be made available for 

interview by the EPA inspector or 

auditor, on request, within a reasonable 

time period. 

(viii) English language translations of 

any documents must be provided to an 

EPA inspector or auditor, on request, 

within 10 working days. 

(ix) English language interpreters 

must be provided to accompany EPA 

inspectors and auditors, on request. 

(2) An agent for service of process 

located in the District of Columbia shall 

be named, and service on this agent 

constitutes service on the foreign refiner 

or any employee of the foreign refiner 

for any action by EPA or otherwise by 

the United States related to the 

requirements of this subpart. 

(3) The forum for any civil or criminal 

enforcement action related to the 

provisions of this section for violations 

of the Clean Air Act or regulations 

promulgated thereunder shall be 

governed by the Clean Air Act, 

including the EPA administrative forum 

where allowed under the Clean Air Act. 

(4) United States substantive and 

procedural laws shall apply to any civil 

or criminal enforcement action against 

the foreign refiner or any employee of 


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the foreign refiner related to the 

provisions of this section. 

(5) Submitting an application for a 

small refinery or small refiner 

exemption, or producing and exporting 

gasoline under such exemption, and all 

other actions to comply with the 

requirements of this subpart relating to 

such exemption constitute actions or 

activities covered by and within the 

meaning of the provisions of 28 U.S.C. 

1605(a)(2), but solely with respect to 

actions instituted against the foreign 

refiner, its agents and employees in any 

court or other tribunal in the United 

States for conduct that violates the 

requirements applicable to the foreign 

refiner under this subpart, including 

conduct that violates the False 

Statements Accountability Act of 1996 

(18 U.S.C. 1001) and section 113(c)(2) of 

the Clean Air Act (42 U.S.C. 7413). 

(6) The foreign refiner, or its agents or 

employees, will not seek to detain or to 

impose civil or criminal remedies 

against EPA inspectors or auditors, 

whether EPA employees or EPA 

contractors, for actions performed 

within the scope of EPA employment 

related to the provisions of this section. 

(7) The commitment required by this 

paragraph (f) shall be signed by the 

owner or president of the foreign refiner 

business. 

(8) In any case where RFS–FRGAS 

produced at a foreign refinery is stored 

or transported by another company 

between the refinery and the vessel that 

transports the RFS–FRGAS to the 

United States, the foreign refiner shall 

obtain from each such other company a 

commitment that meets the 

requirements specified in paragraphs 

(f)(1) through (f)(7) of this section, and 

these commitments shall be included in 

the foreign refiner’s application for a 

small refinery or small refiner 

exemption under this subpart. 

(g) Sovereign immunity. By 

submitting an application for a small 

refinery or small refiner exemption 

under this subpart, or by producing and 

exporting gasoline to the United States 

under such exemption, the foreign 

refiner, and its agents and employees, 

without exception, become subject to 

the full operation of the administrative 

and judicial enforcement powers and 

provisions of the United States without 

limitation based on sovereign immunity, 

with respect to actions instituted against 

the foreign refiner, its agents and 

employees in any court or other tribunal 

in the United States for conduct that 

violates the requirements applicable to 

the foreign refiner under this subpart, 

including conduct that violates the 

False Statements Accountability Act of 

1996 (18 U.S.C. 1001) and section 

113(c)(2) of the Clean Air Act (42 U.S.C. 

7413). 

(h) Bond posting. Any foreign refiner 

shall meet the requirements of this 

paragraph (h) as a condition to approval 

of a small foreign refinery or small 

foreign refiner exemption under this 

subpart. 

(1) The foreign refiner shall post a 

bond of the amount calculated using the 

following equation: 

Bond = G * $0.01 

Where: 

Bond = amount of the bond in United States 

dollars. 

G = the largest volume of gasoline produced 

at the foreign refinery and exported to 

the United States, in gallons, during a 

single calendar year among the most 

recent of the following calendar years, 

up to a maximum of five calendar years: 

The calendar year immediately 

preceding the date the refinery’s 

application is submitted, the calendar 

year the application is submitted, and 

each succeeding calendar year. 

(2) Bonds shall be posted by: 

(i) Paying the amount of the bond to 

the Treasurer of the United States; 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign refiner, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement; or 

(iii) An alternative commitment that 

results in assets of an appropriate 

liquidity and value being readily 

available to the United States, provided 

EPA agrees in advance as to the 

alternative commitment. 

(3) Bonds posted under this paragraph 

(h) shall: 

(i) Be used to satisfy any judicial 

judgment that results from an 

administrative or judicial enforcement 

action for conduct in violation of this 

subpart, including where such conduct 

violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413); 

(ii) Be provided by a corporate surety 

that is listed in the United States 

Department of Treasury Circular 570 

‘‘Companies Holding Certificates of 

Authority as Acceptable Sureties on 

Federal Bonds’’; and 

(iii) Include a commitment that the 

bond will remain in effect for at least 

five years following the end of latest 

annual reporting period that the foreign 

refiner produces gasoline pursuant to 

the requirements of this subpart. 

(4) On any occasion a foreign refiner 

bond is used to satisfy any judgment, 

the foreign refiner shall increase the 

bond to cover the amount used within 

90 days of the date the bond is used. 

(5) If the bond amount for a foreign 

refiner increases, the foreign refiner 

shall increase the bond to cover the 

shortfall within 90 days of the date the 

bond amount changes. If the bond 

amount decreases, the foreign refiner 

may reduce the amount of the bond 

beginning 90 days after the date the 

bond amount changes. 

(i) English language reports. Any 

document submitted to EPA by a foreign 

refiner shall be in English language, or 

shall include an English language 

translation. 

(j) Prohibitions. (1) No person may 

combine RFS–FRGAS with any NonRFS–FRGAS, and no person may 

combine RFS–FRGAS with any RFS– 

FRGAS produced at a different refinery, 

until the importer has met all the 

requirements of paragraph (k) of this 

section. 

(2) No foreign refiner or other person 

may cause another person to commit an 

action prohibited in paragraph (j)(1) of 

this section, or that otherwise violates 

the requirements of this section. 

(k) United States importer 

requirements. Any United States 

importer of RFS–FRGAS shall meet the 

following requirements: 

(1) Each batch of imported RFS– 

FRGAS shall be classified by the 

importer as being RFS–FRGAS. 

(2) Gasoline shall be classified as 

RFS–FRGAS according to the 

designation by the foreign refiner if this 

designation is supported by product 

transfer documents prepared by the 

foreign refiner as required in paragraph 

(c) of this section. Additionally, the 

importer shall comply with all 

requirements of this subpart applicable 

to importers. 

(3) For each gasoline batch classified 

as RFS–FRGAS, any United States 

importer shall have an independent 

third party do all the following: 

(i) Determine the volume of gasoline 

in the vessel. 

(ii) Use the foreign refiner’s RFS– 

FRGAS certification to determine the 

name and EPA-assigned registration 

number of the foreign refinery that 

produced the RFS–FRGAS. 

(iii) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRGAS to the United 

States. 

(iv) Determine the date and time the 

vessel arrives at the United States port 

of entry. 

(4) Any importer shall submit reports 

within 30 days following the date any 

vessel transporting RFS–FRGAS arrives 

at the United States port of entry to: 


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(i) The Administrator containing the 

information determined under 

paragraph (k)(3) of this section; and 

(ii) The foreign refiner containing the 

information determined under 

paragraph (k)(3)(i) of this section, and 

including identification of the port at 

which the product was off loaded. 

(5) Any United States importer shall 

meet all other requirements of this 

subpart for any imported gasoline that is 

not classified as RFS–FRGAS under 

paragraph (k)(2) of this section. 

(l) Truck imports of RFS–FRGAS 

produced at a foreign refinery. (1) Any 

refiner whose RFS–FRGAS is 

transported into the United States by 

truck may petition EPA to use 

alternative procedures to meet all the 

following requirements: 

(i) Certification under paragraph (c)(2) 

of this section. 

(ii) Load port and port of entry testing 

requirements under paragraphs (d) and 

(e) of this section. 

(iii) Importer testing requirements 

under paragraph (k)(3) of this section. 

(2) These alternative procedures must 

ensure RFS–FRGAS remains segregated 

from Non-RFS–FRGAS until it is 

imported into the United States. The 

petition will be evaluated based on 

whether it adequately addresses the 

following: 

(i) Provisions for monitoring pipeline 

shipments, if applicable, from the 

refinery, that ensure segregation of RFS– 

FRGAS from that refinery from all other 

gasoline. 

(ii) Contracts with any terminals and/ 

or pipelines that receive and/or 

transport RFS–FRGAS that prohibit the 

commingling of RFS–FRGAS with NonRFS–FRGAS or RFS–FRGAS from other 

foreign refineries. 

(iii) Attest procedures to be conducted 

annually by an independent third party 

that review loading records and import 

documents based on volume 

reconciliation, or other criteria, to 

confirm that all RFS–FRGAS remains 

segregated throughout the distribution 

system. 

(3) The petition described in this 

section must be submitted to EPA along 

with the application for a small refinery 

or small refiner exemption under this 

subpart. 

(m) Additional attest requirements for 

importers of RFS–FRGAS. The following 

additional procedures shall be carried 

out by any importer of RFS–FRGAS as 

part of the attest engagement required 

for importers under this subpart K. 

(1) Obtain listings of all tenders of 

RFS–FRGAS. Agree the total volume of 

tenders from the listings to the gasoline 

inventory reconciliation analysis 

required in § 80.133(b), and to the 

volumes determined by the third party 

under paragraph (d) of this section. 

(2) For each tender under paragraph 

(m)(1) of this section, where the gasoline 

is loaded onto a marine vessel, report as 

a finding the name and country of 

registration of each vessel, and the 

volumes of RFS–FRGAS loaded onto 

each vessel. 

(3) Select a sample from the list of 

vessels identified in paragraph (m)(2) of 

this section used to transport RFS– 

FRGAS, in accordance with the 

guidelines in § 80.127, and for each 

vessel selected perform the following: 

(i) Obtain the report of the 

independent third party, under 

paragraph (d) of this section. 

(A) Agree the information in these 

reports with regard to vessel 

identification and gasoline volume. 

(B) Identify, and report as a finding, 

each occasion the load port and port of 

entry volume results differ by more than 

the amount allowed in paragraph (e)(2) 

of this section, and determine whether 

all of the requirements of paragraph 

(e)(2) of this section have been met. 

(ii) Obtain the documents used by the 

independent third party to determine 

transportation and storage of the RFS– 

FRGAS from the refinery to the load 

port, under paragraph (d) of this section. 

Obtain tank activity records for any 

storage tank where the RFS–FRGAS is 

stored, and pipeline activity records for 

any pipeline used to transport the RFS– 

FRGAS prior to being loaded onto the 

vessel. Use these records to determine 

whether the RFS–FRGAS was produced 

at the refinery that is the subject of the 

attest engagement, and whether the 

RFS–FRGAS was mixed with any NonRFS–FRGAS or any RFS–FRGAS 

produced at a different refinery. 

(4) Select a sample from the list of 

vessels identified in paragraph (m)(2) of 

this section used to transport RFS– 

FRGAS, in accordance with the 

guidelines in § 80.127, and for each 

vessel selected perform the following: 

(i) Obtain a commercial document of 

general circulation that lists vessel 

arrivals and departures, and that 

includes the port and date of departure 

of the vessel, and the port of entry and 

date of arrival of the vessel. 

(ii) Agree the vessel’s departure and 

arrival locations and dates from the 

independent third party and United 

States importer reports to the 

information contained in the 

commercial document. 

(5) Obtain separate listings of all 

tenders of RFS–FRGAS, and perform the 

following: 

(i) Agree the volume of tenders from 

the listings to the gasoline inventory 

reconciliation analysis in § 80.133(b). 

(ii) Obtain a separate listing of the 

tenders under this paragraph (m)(5) 

where the gasoline is loaded onto a 

marine vessel. Select a sample from this 

listing in accordance with the 

guidelines in § 80.127, and obtain a 

commercial document of general 

circulation that lists vessel arrivals and 

departures, and that includes the port 

and date of departure and the ports and 

dates where the gasoline was off loaded 

for the selected vessels. Determine and 

report as a finding the country where 

the gasoline was off loaded for each 

vessel selected. 

(6) In order to complete the 

requirements of this paragraph (m), an 

auditor shall: 

(i) Be independent of the foreign 

refiner or importer; 

(ii) Be licensed as a Certified Public 

Accountant in the United States and a 

citizen of the United States, or be 

approved in advance by EPA based on 

a demonstration of ability to perform the 

procedures required in §§ 80.125 

through 80.127, 80.130, 80.1164, and 

this paragraph (m); and 

(iii) Sign a commitment that contains 

the provisions specified in paragraph (f) 

of this section with regard to activities 

and documents relevant to compliance 

with the requirements of §§ 80.125 

through 80.127, 80.130, 80.1164, and 

this paragraph (m). 

(n) Withdrawal or suspension of 

foreign refiner status. EPA may 

withdraw or suspend a foreign refiner’s 

small refinery or small refiner 

exemption where: 

(1) A foreign refiner fails to meet any 

requirement of this section; 

(2) A foreign government fails to 

allow EPA inspections as provided in 

paragraph (f)(1) of this section; 

(3) A foreign refiner asserts a claim of, 

or a right to claim, sovereign immunity 

in an action to enforce the requirements 

in this subpart; or 

(4) A foreign refiner fails to pay a civil 

or criminal penalty that is not satisfied 

using the foreign refiner bond specified 

in paragraph (h) of this section. 

(o) Additional requirements for 

applications, reports and certificates. 

Any application for a small refinery or 

small refiner exemption, alternative 

procedures under paragraph (l) of this 

section, any report, certification, or 

other submission required under this 

section shall be: 

(1) Submitted in accordance with 

procedures specified by the 

Administrator, including use of any 

forms that may be specified by the 

Administrator. 

(2) Be signed by the president or 

owner of the foreign refiner company, or 

by that person’s immediate designee, 


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and shall contain the following 

declaration: 

I hereby certify: (1) That I have actual 

authority to sign on behalf of and to bind 

[NAME OF FOREIGN REFINER] with regard 

to all statements contained herein; (2) that I 

am aware that the information contained 

herein is being Certified, or submitted to the 

United States Environmental Protection 

Agency, under the requirements of 40 CFR 

part 80, subpart K, and that the information 

is material for determining compliance under 

these regulations; and (3) that I have read and 

understand the information being Certified or 

submitted, and this information is true, 

complete and correct to the best of my 

knowledge and belief after I have taken 

reasonable and appropriate steps to verify the 

accuracy thereof. I affirm that I have read and 

understand the provisions of 40 CFR part 80, 

subpart K, including 40 CFR 80.1165 apply 

to [NAME OF FOREIGN REFINER]. Pursuant 

to Clean Air Act section 113(c) and 18 U.S.C. 

1001, the penalty for furnishing false, 

incomplete or misleading information in this 

certification or submission is a fine of up to 

$10,000 U.S., and/or imprisonment for up to 

five years.’’ 

§ 80.1166 What are the additional 

requirements under this subpart for a 

foreign producer of cellulosic biomass 

ethanol or waste derived ethanol? 

(a) Foreign producer of cellulosic 

biomass ethanol or waste derived 

ethanol. For purposes of this subpart, a 

foreign producer of cellulosic biomass 

ethanol or waste derived ethanol is a 

person located outside the United 

States, the Commonwealth of Puerto 

Rico, the Virgin Islands, Guam, 

American Samoa, and the 

Commonwealth of the Northern Mariana 

Islands (collectively referred to in this 

section as ’’the United States’’) that has 

been approved by EPA to assign RINs to 

cellulosic biomass ethanol or waste 

derived ethanol that the foreign 

producer produces and exports to the 

United States, hereinafter referred to as 

a ‘‘foreign producer’’ under this section. 

(b) General requirements. (1) An 

approved foreign producer under this 

section must meet all requirements that 

apply to cellulosic biomass ethanol or 

waste derived ethanol producers under 

this subpart, except to the extent 

otherwise specified in paragraph (b)(2) 

of this section. 

(2)(i) The independent third party that 

conducts the facility verification 

required under § 80.1155(a) must 

inspect the foreign producer’s facility 

and submit a report to EPA which 

describes in detail the physical plant 

and its operation. 

(ii) The independent third party that 

conducts the facility verification 

required under § 80.1155(a) must be a 

licensed Professional Engineer in the 

chemical engineering field, but need not 

be based in the United States. The 

independent third party must include 

documentation of its qualifications as a 

licensed Professional Engineer in the 

report required in paragraph (b)(2)(i) of 

this section. 

(iii) The requirements of paragraphs 

(b)(2)(i) and (ii) of this section must be 

met before a foreign entity may be 

approved as a foreign producer under 

this subpart. 

(c) Designation, foreign producer 

certification, and product transfer 

documents. 

(1) Any approved foreign producer 

under this section must designate each 

batch of cellulosic biomass ethanol or 

waste derived ethanol as ‘‘RFS–FRETH’’ 

at the time the ethanol is produced. 

(2) On each occasion when RFS– 

FRETH is loaded onto a vessel or other 

transportation mode for transport to the 

United States, the foreign producer shall 

prepare a certification for each batch of 

RFS–FRETH; the certification shall 

include the report of the independent 

third party under paragraph (d) of this 

section, and all the following additional 

information: 

(i) The name and EPA registration 

number of the company that produced 

the RFS–FRETH. 

(ii) The identification of the ethanol 

as RFS–FRETH. 

(iii) The volume of RFS–FRETH being 

transported, in gallons. 

(3) On each occasion when any 

person transfers custody or title to any 

RFS–FRETH prior to its being imported 

into the United States, it must include 

all the following information as part of 

the product transfer document 

information: 

(i) Designation of the ethanol as RFS– 

FRETH. 

(ii) The certification required under 

paragraph (c)(2) of this section. 

(d) Load port independent testing and 

refinery identification. (1) On each 

occasion that RFS–FRETH is loaded 

onto a vessel for transport to the United 

States the foreign producer shall have 

an independent third party do all the 

following: 

(i) Inspect the vessel prior to loading 

and determine the volume of any tank 

bottoms. 

(ii) Determine the volume of RFS– 

FRETH loaded onto the vessel 

(exclusive of any tank bottoms before 

loading). 

(iii) Obtain the EPA-assigned 

registration number of the foreign 

producer. 

(iv) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRETH to the United 

States. 

(v) Determine the date and time the 

vessel departs the port serving the 

foreign producer. 

(vi) Review original documents that 

reflect movement and storage of the 

RFS–FRETH from the foreign producer 

to the load port, and from this review 

determine the following: 

(A) The facility at which the RFS– 

FRETH was produced. 

(B) That the RFS–FRETH remained 

segregated from Non-RFS–FRETH and 

other RFS–FRETH produced by a 

different foreign producer. 

(2) The independent third party shall 

submit a report to the following: 

(i) The foreign producer containing 

the information required under 

paragraph (d)(1) of this section, to 

accompany the product transfer 

documents for the vessel. 

(ii) The Administrator containing the 

information required under paragraph 

(d)(1) of this section, within thirty days 

following the date of the independent 

third party’s inspection. This report 

shall include a description of the 

method used to determine the identity 

of the foreign producer facility at which 

the ethanol was produced, assurance 

that the ethanol remained segregated as 

specified in paragraph (j)(1) of this 

section, and a description of the 

ethanol’s movement and storage 

between production at the source 

facility and vessel loading. 

(3) The independent third party must: 

(i) Be approved in advance by EPA, 

based on a demonstration of ability to 

perform the procedures required in this 

paragraph (d); 

(ii) Be independent under the criteria 

specified in § 80.65(e)(2)(iii); and 

(iii) Sign a commitment that contains 

the provisions specified in paragraph (f) 

of this section with regard to activities, 

facilities and documents relevant to 

compliance with the requirements of 

this paragraph (d). 

(e) Comparison of load port and port 

of entry testing. (1)(i) Any foreign 

producer and any United States 

importer of RFS–FRETH shall compare 

the results from the load port testing 

under paragraph (d) of this section, with 

the port of entry testing as reported 

under paragraph (k) of this section, for 

the volume of ethanol, except as 

specified in paragraph (e)(1)(ii) of this 

section. 

(ii) Where a vessel transporting RFS– 

FRETH off loads the ethanol at more 

than one United States port of entry, the 

requirements of paragraph (e)(1)(i) of 

this section do not apply at subsequent 

ports of entry if the United States 

importer obtains a certification from the 

vessel owner that the requirements of 

paragraph (e)(1)(i) of this section were 


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met and that the vessel has not loaded 

any ethanol between the first United 

States port of entry and the subsequent 

port of entry. 

(2)(i) If the temperature-corrected 

volumes determined at the port of entry 

and at the load port differ by more than 

one percent, the number of RINs 

associated with the ethanol shall be 

calculated based on the lesser of the two 

volumes in paragraph (e)(1)(i) of this 

section. 

(ii) Where the port of entry volume is 

the lesser of the two volumes in 

paragraph (e)(1)(i) of this section, the 

importer shall calculate the difference 

between the number of RINs originally 

assigned by the foreign producer and 

the number of RINs calculated under 

§ 80.1126 for the volume of ethanol as 

measured at the port of entry, and retire 

that amount of RINs in accordance with 

paragraph (k)(4) of this section. 

(f) Foreign producer commitments. 

Any foreign producer shall commit to 

and comply with the provisions 

contained in this paragraph (f) as a 

condition to being approved as a foreign 

producer under this subpart. 

(1) Any United States Environmental 

Protection Agency inspector or auditor 

must be given full, complete and 

immediate access to conduct 

inspections and audits of the foreign 

producer facility. 

(i) Inspections and audits may be 

either announced in advance by EPA, or 

unannounced. 

(ii) Access will be provided to any 

location where: 

(A) Ethanol is produced; 

(B) Documents related to ethanol 

producer operations are kept; and 

(C) RFS–FRETH is stored or 

transported between the foreign 

producer and the United States, 

including storage tanks, vessels and 

pipelines. 

(iii) Inspections and audits may be by 

EPA employees or contractors to EPA. 

(iv) Any documents requested that are 

related to matters covered by 

inspections and audits must be 

provided to an EPA inspector or auditor 

on request. 

(v) Inspections and audits by EPA 

may include review and copying of any 

documents related to the following: 

(A) The volume of RFS–FRETH. 

(B) The proper classification of 

gasoline as being RFS–FRETH; 

(C) Transfers of title or custody to 

RFS–FRETH. 

(D) Work performed and reports 

prepared by independent third parties 

and by independent auditors under the 

requirements of this section, including 

work papers. 

(vi) Inspections and audits by EPA 

may include interviewing employees. 

(vii) Any employee of the foreign 

producer must be made available for 

interview by the EPA inspector or 

auditor, on request, within a reasonable 

time period. 

(viii) English language translations of 

any documents must be provided to an 

EPA inspector or auditor, on request, 

within 10 working days. 

(ix) English language interpreters 

must be provided to accompany EPA 

inspectors and auditors, on request. 

(2) An agent for service of process 

located in the District of Columbia shall 

be named, and service on this agent 

constitutes service on the foreign 

producer or any employee of the foreign 

producer for any action by EPA or 

otherwise by the United States related to 

the requirements of this subpart. 

(3) The forum for any civil or criminal 

enforcement action related to the 

provisions of this section for violations 

of the Clean Air Act or regulations 

promulgated thereunder shall be 

governed by the Clean Air Act, 

including the EPA administrative forum 

where allowed under the Clean Air Act. 

(4) United States substantive and 

procedural laws shall apply to any civil 

or criminal enforcement action against 

the foreign producer or any employee of 

the foreign producer related to the 

provisions of this section. 

(5) Applying to be an approved 

foreign producer under this section, or 

producing or exporting ethanol under 

such approval, and all other actions to 

comply with the requirements of this 

subpart relating to such approval 

constitute actions or activities covered 

by and within the meaning of the 

provisions of 28 U.S.C. 1605(a)(2), but 

solely with respect to actions instituted 

against the foreign producer, its agents 

and employees in any court or other 

tribunal in the United States for conduct 

that violates the requirements 

applicable to the foreign producer under 

this subpart, including conduct that 

violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413). 

(6) The foreign producer, or its agents 

or employees, will not seek to detain or 

to impose civil or criminal remedies 

against EPA inspectors or auditors, 

whether EPA employees or EPA 

contractors, for actions performed 

within the scope of EPA employment 

related to the provisions of this section. 

(7) The commitment required by this 

paragraph (f) shall be signed by the 

owner or president of the foreign 

producer company. 

(8) In any case where RFS–FRETH 

produced at a foreign producer facility 

is stored or transported by another 

company between the refinery and the 

vessel that transports the RFS–FRETH to 

the United States, the foreign producer 

shall obtain from each such other 

company a commitment that meets the 

requirements specified in paragraphs 

(f)(1) through (7) of this section, and 

these commitments shall be included in 

the foreign producer’s application to be 

an approved foreign producer under this 

subpart. 

(g) Sovereign immunity. By 

submitting an application to be an 

approved foreign producer under this 

subpart, or by producing and exporting 

ethanol to the United States under such 

approval, the foreign producer, and its 

agents and employees, without 

exception, become subject to the full 

operation of the administrative and 

judicial enforcement powers and 

provisions of the United States without 

limitation based on sovereign immunity, 

with respect to actions instituted against 

the foreign producer, its agents and 

employees in any court or other tribunal 

in the United States for conduct that 

violates the requirements applicable to 

the foreign producer under this subpart, 

including conduct that violates the 

False Statements Accountability Act of 

1996 (18 U.S.C. 1001) and section 

113(c)(2) of the Clean Air Act (42 U.S.C. 

7413). 

(h) Bond posting. Any foreign 

producer shall meet the requirements of 

this paragraph (h) as a condition to 

approval as a foreign producer under 

this subpart. 

(1) The foreign producer shall post a 

bond of the amount calculated using the 

following equation: 

Bond = G * $ 0.01 

Where: 

Bond = amount of the bond in U.S. dollars. 

G = The largest volume of ethanol produced 

at the foreign producer’s facility and 

exported to the United States, in gallons, 

during a single calendar year among the 

most recent of the following calendar 

years, up to a maximum of five calendar 

years: The calendar year immediately 

preceding the date the refinery’s 

application is submitted, the calendar 

year the application is submitted, and 

each succeeding calendar year. 

(2) Bonds shall be posted by any of 

the following methods: 

(i) Paying the amount of the bond to 

the Treasurer of the United States. 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign producer, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement. 


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(iii) An alternative commitment that 

results in assets of an appropriate 

liquidity and value being readily 

available to the United States provided 

EPA agrees in advance as to the 

alternative commitment. 

(3) Bonds posted under this paragraph 

(h) shall: 

(i) Be used to satisfy any judicial 

judgment that results from an 

administrative or judicial enforcement 

action for conduct in violation of this 

subpart, including where such conduct 

violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413); 

(ii) Be provided by a corporate surety 

that is listed in the United States 

Department of Treasury Circular 570 

’’Companies Holding Certificates of 

Authority as Acceptable Sureties on 

Federal Bonds’’; and 

(iii) Include a commitment that the 

bond will remain in effect for at least 

five years following the end of the latest 

annual reporting period that the foreign 

producer produces ethanol pursuant to 

the requirements of this subpart. 

(4) On any occasion a foreign 

producer bond is used to satisfy any 

judgment, the foreign producer shall 

increase the bond to cover the amount 

used within 90 days of the date the 

bond is used. 

(5) If the bond amount for a foreign 

producer increases, the foreign producer 

shall increase the bond to cover the 

shortfall within 90 days of the date the 

bond amount changes. If the bond 

amount decreases, the foreign refiner 

may reduce the amount of the bond 

beginning 90 days after the date the 

bond amount changes. 

(i) English language reports. Any 

document submitted to EPA by a foreign 

producer shall be in English language, 

or shall include an English language 

translation. 

(j) Prohibitions. (1) No person may 

combine RFS–FRETH with any NonRFS–FRETH, and no person may 

combine RFS–FRETH with any RFS– 

FRETH produced at a different refinery, 

until the importer has met all the 

requirements of paragraph (k) of this 

section. 

(2) No foreign producer or other 

person may cause another person to 

commit an action prohibited in 

paragraph (j)(1) of this section, or that 

otherwise violates the requirements of 

this section. 

(k) Requirements for United States 

importers of RFS–FRETH. Any United 

States importer shall meet the following 

requirements: 

(1) Each batch of imported RFS– 

FRETH shall be classified by the 

importer as being RFS–FRETH. 

(2) Ethanol shall be classified as RFS– 

FRETH according to the designation by 

the foreign producer if this designation 

is supported by product transfer 

documents prepared by the foreign 

producer as required in paragraph (c) of 

this section. 

(3) For each ethanol batch classified 

as RFS–FRETH, any United States 

importer shall have an independent 

third party do all the following: 

(i) Determine the volume of gasoline 

in the vessel. 

(ii) Use the foreign producer’s RFS– 

FRETH certification to determine the 

name and EPA-assigned registration 

number of the foreign producer that 

produced the RFS–FRETH. 

(iii) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRETH to the United 

States. 

(iv) Determine the date and time the 

vessel arrives at the United States port 

of entry. 

(4) Where the importer is required to 

retire RINs under paragraph (e)(2) of this 

section, the importer must report the 

retired RINs in the applicable reports 

under § 80.1152. 

(5) Any importer shall submit reports 

within 30 days following the date any 

vessel transporting RFS–FRETH arrives 

at the United States port of entry to the 

following: 

(i) The Administrator containing the 

information determined under 

paragraph (k)(3) of this section. 

(ii) The foreign producer containing 

the information determined under 

paragraph (k)(3)(i) of this section, and 

including identification of the port at 

which the product was off loaded, and 

any RINs retired under paragraph (e)(2) 

of this section. 

(6) Any United States importer shall 

meet all other requirements of this 

subpart for any imported ethanol or 

other renewable fuel that is not 

classified as RFS–FRETH under 

paragraph (k)(2) of this section. 

(l) Truck imports of RFS–FRETH 

produced by a foreign producer. (1) Any 

foreign producer whose RFS–FRETH is 

transported into the United States by 

truck may petition EPA to use 

alternative procedures to meet all the 

following requirements: 

(i) Certification under paragraph (c)(2) 

of this section. 

(ii) Load port and port of entry testing 

under paragraphs (d) and (e) of this 

section. 

(iii) Importer testing under paragraph 

(k)(3) of this section. 

(2) These alternative procedures must 

ensure RFS–FRETH remains segregated 

from Non-RFS–FRETH until it is 

imported into the United States. The 

petition will be evaluated based on 

whether it adequately addresses the 

following: 

(i) Contracts with any facilities that 

receive and/or transport RFS–FRETH 

that prohibit the commingling of RFS– 

FRETH with Non-RFS–FRETH or RFS– 

FRETH from other foreign producers. 

(ii) Attest procedures to be conducted 

annually by an independent third party 

that review loading records and import 

documents based on volume 

reconciliation to confirm that all RFS– 

FRETH remains segregated. 

(3) The petition described in this 

section must be submitted to EPA along 

with the application for approval as a 

foreign producer under this subpart. 

(m) Additional attest requirements for 

producers of RFS–FRETH. The 

following additional procedures shall be 

carried out by any producer of RFS– 

FRETH as part of the attest engagement 

required for renewable fuel producers 

under this subpart K. 

(1) Obtain listings of all tenders of 

RFS–FRETH. Agree the total volume of 

tenders from the listings to the volumes 

determined by the third party under 

paragraph (d) of this section. 

(2) For each tender under paragraph 

(m)(1) of this section, where the ethanol 

is loaded onto a marine vessel, report as 

a finding the name and country of 

registration of each vessel, and the 

volumes of RFS–FRETH loaded onto 

each vessel. 

(3) Select a sample from the list of 

vessels identified in paragraph (m)(2) of 

this section used to transport RFS– 

FRETH, in accordance with the 

guidelines in § 80.127, and for each 

vessel selected perform the following: 

(i) Obtain the report of the 

independent third party, under 

paragraph (d) of this section, and of the 

United States importer under paragraph 

(k) of this section. 

(A) Agree the information in these 

reports with regard to vessel 

identification and ethanol volume. 

(B) Identify, and report as a finding, 

each occasion the load port and port of 

entry volume results differ by more than 

the amount allowed in paragraph (e) of 

this section, and determine whether the 

importer retired the appropriate amount 

of RINs as required under paragraph 

(e)(2) of this section, and submitted the 

applicable reports under § 80.1152 in 

accordance with paragraph (k)(4) of this 

section. 

(ii) Obtain the documents used by the 

independent third party to determine 

transportation and storage of the RFS– 

FRETH from the foreign producer’s 

facility to the load port, under 


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paragraph (d) of this section. Obtain 

tank activity records for any storage tank 

where the RFS–FRETH is stored, and 

activity records for any mode of 

transportation used to transport the 

RFS–FRGAS prior to being loaded onto 

the vessel. Use these records to 

determine whether the RFS–FRETH was 

produced at the foreign producer’s 

facility that is the subject of the attest 

engagement, and whether the RFS– 

FRETH was mixed with any Non-RFS– 

FRETH or any RFS–FRETH produced at 

a different facility. 

(4) Select a sample from the list of 

vessels identified in paragraph (m)(2) of 

this section used to transport RFS– 

FRETH, in accordance with the 

guidelines in § 80.127, and for each 

vessel selected perform the following: 

(i) Obtain a commercial document of 

general circulation that lists vessel 

arrivals and departures, and that 

includes the port and date of departure 

of the vessel, and the port of entry and 

date of arrival of the vessel. 

(ii) Agree the vessel’s departure and 

arrival locations and dates from the 

independent third party and United 

States importer reports to the 

information contained in the 

commercial document. 

(5) Obtain a separate listing of the 

tenders under this paragraph (m)(5) 

where the gasoline is loaded onto a 

marine vessel. Select a sample from this 

listing in accordance with the 

guidelines in § 80.127, and obtain a 

commercial document of general 

circulation that lists vessel arrivals and 

departures, and that includes the port 

and date of departure and the ports and 

dates where the ethanol was off loaded 

for the selected vessels. Determine and 

report as a finding the country where 

the ethanol was off loaded for each 

vessel selected. 

(6) In order to complete the 

requirements of this paragraph (m) an 

auditor shall: 

(i) Be independent of the foreign 

producer; 

(ii) Be licensed as a Certified Public 

Accountant in the United States and a 

citizen of the United States, or be 

approved in advance by EPA based on 

a demonstration of ability to perform the 

procedures required in §§ 80.125 

through 80.127, 80.130, 80.1164, and 

this paragraph (m); and 

(iii) Sign a commitment that contains 

the provisions specified in paragraph (f) 

of this section with regard to activities 

and documents relevant to compliance 

with the requirements of §§ 80.125 

through 80.127, 80.130, 80.1164, and 

this paragraph (m). 

(n) Withdrawal or suspension of 

foreign producer approval. EPA may 

withdraw or suspend a foreign 

producer’s approval where any of the 

following occur: 

(1) A foreign producer fails to meet 

any requirement of this section. 

(2) A foreign government fails to 

allow EPA inspections as provided in 

paragraph (f)(1) of this section. 

(3) A foreign producer asserts a claim 

of, or a right to claim, sovereign 

immunity in an action to enforce the 

requirements in this subpart. 

(4) A foreign producer fails to pay a 

civil or criminal penalty that is not 

satisfied using the foreign producer 

bond specified in paragraph (g) of this 

section. 

(o) Additional requirements for 

applications, reports and certificates. 

Any application for approval as a 

foreign producer, alternative procedures 

under paragraph (l) of this section, any 

report, certification, or other submission 

required under this section shall be: 

(1) Submitted in accordance with 

procedures specified by the 

Administrator, including use of any 

forms that may be specified by the 

Administrator. 

(2) Signed by the president or owner 

of the foreign producer company, or by 

that person’s immediate designee, and 

shall contain the following declaration: 

I hereby certify: (1) That I have actual 

authority to sign on behalf of and to bind 

[insert name of foreign producer] with regard 

to all statements contained herein; (2) that I 

am aware that the information contained 

herein is being Certified, or submitted to the 

United States Environmental Protection 

Agency, under the requirements of 40 CFR 

part 80, subpart K, and that the information 

is material for determining compliance under 

these regulations; and (3) that I have read and 

understand the information being Certified or 

submitted, and this information is true, 

complete and correct to the best of my 

knowledge and belief after I have taken 

reasonable and appropriate steps to verify the 

accuracy thereof. I affirm that I have read and 

understand the provisions of 40 CFR part 80, 

subpart K, including 40 CFR 80.1165 apply 

to [insert name of foreign producer]. Pursuant 

to Clean Air Act section 113(c) and 18 U.S.C. 

1001, the penalty for furnishing false, 

incomplete or misleading information in this 

certification or submission is a fine of up to 

$10,000 U.S., and/or imprisonment for up to 

five years. 

§ 80.1167 What are the additional 

requirements under this subpart for a 

foreign RIN owner? 

(a) Foreign RIN owner. For purposes 

of this subpart, a foreign RIN owner is 

a person located outside the United 

States, the Commonwealth of Puerto 

Rico, the Virgin Islands, Guam, 

American Samoa, and the 

Commonwealth of the Northern Mariana 

Islands (collectively referred to in this 

section as ‘‘the United States’’) that has 

been approved by EPA to own RINs. 

(b) General Requirement. An 

approved foreign RIN owner must meet 

all requirements that apply to persons 

who own RINs under this subpart. 

(c) Foreign RIN owner commitments. 

Any person shall commit to and comply 

with the provisions contained in this 

paragraph (c) as a condition to being 

approved as a foreign RIN owner under 

this subpart. 

(1) Any United States Environmental 

Protection Agency inspector or auditor 

must be given full, complete and 

immediate access to conduct 

inspections and audits of the foreign 

RIN owner’s place of business. 

(i) Inspections and audits may be 

either announced in advance by EPA, or 

unannounced; and 

(ii) Access will be provided to any 

location where documents related to 

RINs the foreign RIN owner has 

obtained, sold, transferred or held are 

kept. 

(iii) Inspections and audits may be by 

EPA employees or contractors to EPA. 

(iv) Any documents requested that are 

related to matters covered by 

inspections and audits must be 

provided to an EPA inspector or auditor 

on request. 

(v) Inspections and audits by EPA 

may include review and copying of any 

documents related to the following: 

(A) Transfers of title to RINs. 

(B) Work performed and reports 

prepared by independent auditors under 

the requirements of this section, 

including work papers. 

(vi) Inspections and audits by EPA 

may include interviewing employees. 

(vii) Any employee of the foreign RIN 

owner must be made available for 

interview by the EPA inspector or 

auditor, on request, within a reasonable 

time period. 

(viii) English language translations of 

any documents must be provided to an 

EPA inspector or auditor, on request, 

within 10 working days. 

(ix) English language interpreters 

must be provided to accompany EPA 

inspectors and auditors, on request. 

(2) An agent for service of process 

located in the District of Columbia shall 

be named, and service on this agent 

constitutes service on the foreign RIN 

owner or any employee of the foreign 

RIN owner for any action by EPA or 

otherwise by the United States related to 

the requirements of this subpart. 

(3) The forum for any civil or criminal 

enforcement action related to the 

provisions of this section for violations 

of the Clean Air Act or regulations 

promulgated thereunder shall be 

governed by the Clean Air Act, 


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including the EPA administrative forum 

where allowed under the Clean Air Act. 

(4) United States substantive and 

procedural laws shall apply to any civil 

or criminal enforcement action against 

the foreign RIN owner or any employee 

of the foreign RIN owner related to the 

provisions of this section. 

(5) Submitting an application to be a 

foreign RIN owner, and all other actions 

to comply with the requirements of this 

subpart constitute actions or activities 

covered by and within the meaning of 

the provisions of 28 U.S.C. 1605(a)(2), 

but solely with respect to actions 

instituted against the foreign RIN owner, 

its agents and employees in any court or 

other tribunal in the United States for 

conduct that violates the requirements 

applicable to the foreign RIN owner 

under this subpart, including conduct 

that violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413). 

(6) The foreign RIN owner, or its 

agents or employees, will not seek to 

detain or to impose civil or criminal 

remedies against EPA inspectors or 

auditors, whether EPA employees or 

EPA contractors, for actions performed 

within the scope of EPA employment 

related to the provisions of this section. 

(7) The commitment required by this 

paragraph (c) shall be signed by the 

owner or president of the foreign RIN 

owner business. 

(d) Sovereign immunity. By 

submitting an application to be a foreign 

RIN owner under this subpart, the 

foreign entity, and its agents and 

employees, without exception, become 

subject to the full operation of the 

administrative and judicial enforcement 

powers and provisions of the United 

States without limitation based on 

sovereign immunity, with respect to 

actions instituted against the foreign 

RIN owner, its agents and employees in 

any court or other tribunal in the United 

States for conduct that violates the 

requirements applicable to the foreign 

RIN owner under this subpart, including 

conduct that violates the False 

Statements Accountability Act of 1996 

(18 U.S.C. 1001) and section 113(c)(2) of 

the Clean Air Act (42 U.S.C. 7413). 

(e) Bond posting. Any foreign entity 

shall meet the requirements of this 

paragraph (d) as a condition to approval 

as a foreign RIN owner under this 

subpart. 

(1) The foreign entity shall post a 

bond of the amount calculated using the 

following equation: 

Bond = G * $0.01 

Where: 

Bond = amount of the bond in U.S. dollars. 

G = The total of the number of gallon-RINs 

the foreign entity expects to sell or 

transfer during the first calendar year 

that the foreign entity is a RIN owner, 

plus the number of gallon-RINs the 

foreign entity expects to sell or transfer 

during the next four calendar years. After 

the first calendar year, the bond amount 

shall be based on the actual number of 

gallon-RINs sold or transferred during 

the current calendar year and the 

number held at the conclusion of the 

current averaging year, plus the number 

of gallon-RINs sold or transferred during 

the four most recent calendar years 

preceding the current calendar year. For 

any year for which there were fewer than 

four preceding years in which the foreign 

entity sold or transferred RINs, the bond 

shall be based on the total of the number 

of gallon-RINs sold or transferred during 

the current calendar year and the 

number held at the end of the current 

calendar year, plus the number of gallonRINs sold or transferred during any 

calendar year preceding the current 

calendar year, plus the number of gallonRINs expected to be sold or transferred 

during subsequent calendar years, the 

total number of years not to exceed four 

calendar years in addition to the current 

calendar year. 

(2) Bonds shall be posted by doing 

any of the following: 

(i) Paying the amount of the bond to 

the Treasurer of the United States. 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign RIN owner, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement. 

(iii) An alternative commitment that 

results in assets of an appropriate 

liquidity and value being readily 

available to the United States, provided 

EPA agrees in advance as to the 

alternative commitment. 

(3) Bonds posted under this paragraph 

(e) shall: 

(i) Be used to satisfy any judicial 

judgment that results from an 

administrative or judicial enforcement 

action for conduct in violation of this 

subpart, including where such conduct 

violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413); 

(ii) Be provided by a corporate surety 

that is listed in the United States 

Department of Treasury Circular 570 

‘‘Companies Holding Certificates of 

Authority as Acceptable Sureties on 

Federal Bonds’’; and 

(iii) Include a commitment that the 

bond will remain in effect for at least 

five years following the end of latest 

reporting period in which the foreign 

RIN owner obtains, sells, transfers or 

holds RINs. 

(4) On any occasion a foreign RIN 

owner bond is used to satisfy any 

judgment, the foreign RIN owner shall 

increase the bond to cover the amount 

used within 90 days of the date the 

bond is used. 

(f) English language reports. Any 

document submitted to EPA by a foreign 

RIN owner shall be in English language, 

or shall include an English language 

translation. 

(g) Prohibitions. (1) A foreign RIN 

owner is prohibited from obtaining, 

selling, transferring or holding any RIN 

that is in excess of the number for 

which the bond requirements of this 

section have been satisfied. 

(2) Any RIN that is sold, transferred 

or held that is in excess of the number 

for which the bond requirements of this 

section have been satisfied is an invalid 

RIN under § 80.1131. 

(3) Any RIN that is obtained from a 

person located outside the United States 

that is not an approved foreign RIN 

owner under this section is an invalid 

RIN under § 80.1131. 

(4) No foreign RIN owner or other 

person may cause another person to 

commit an action prohibited in this 

paragraph (g), or that otherwise violates 

the requirements of this section. 

(h) Additional attest requirements for 

foreign RIN owners. The following 

additional requirements apply to any 

foreign RIN owner as part of the attest 

engagement required for RIN owners 

under this subpart K. 

(1) The attest auditor must be 

independent of the foreign RIN owner. 

(2) The attest auditor must be licensed 

as a Certified Public Accountant in the 

United States and a citizen of the United 

States, or be approved in advance by 

EPA based on a demonstration of ability 

to perform the procedures required in 

§§ 80.125 through 80.127, 80.130, and 

80.1164. 

(3) The attest auditor must sign a 

commitment that contains the 

provisions specified in paragraph (c) of 

this section with regard to activities and 

documents relevant to compliance with 

the requirements of §§ 80.125 through 

80.127, 80.130, and 80.1164. 

(i) Withdrawal or suspension of 

foreign RIN owner status. EPA may 

withdraw or suspend its approval of a 

foreign RIN owner where any of the 

following occur: 

(1) A foreign RIN owner fails to meet 

any requirement of this section, 

including, but not limited to, the bond 

requirements. 

(2) A foreign government fails to 

allow EPA inspections as provided in 

paragraph (c)(1) of this section. 


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24014 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

(3) A foreign RIN owner asserts a 

claim of, or a right to claim, sovereign 

immunity in an action to enforce the 

requirements in this subpart. 

(4) A foreign RIN owner fails to pay 

a civil or criminal penalty that is not 

satisfied using the foreign RIN owner 

bond specified in paragraph (e) of this 

section. 

(j) Additional requirements for 

applications, reports and certificates. 

Any application for approval as a 

foreign RIN owner, any report, 

certification, or other submission 

required under this section shall be: 

(1) Submitted in accordance with 

procedures specified by the 

Administrator, including use of any 

forms that may be specified by the 

Administrator. 

(2) Signed by the president or owner 

of the foreign RIN owner company, or 

that person’s immediate designee, and 

shall contain the following declaration: 

I hereby certify: (1) That I have actual 

authority to sign on behalf of and to bind 

[insert name of foreign RIN owner] with 

regard to all statements contained herein; (2) 

that I am aware that the information 

contained herein is being Certified, or 

submitted to the United States 

Environmental Protection Agency, under the 

requirements of 40 CFR part 80, subpart K, 

and that the information is material for 

determining compliance under these 

regulations; and (3) that I have read and 

understand the information being Certified or 

submitted, and this information is true, 

complete and correct to the best of my 

knowledge and belief after I have taken 

reasonable and appropriate steps to verify the 

accuracy thereof. I affirm that I have read and 

understand the provisions of 40 CFR part 80, 

subpart K, including 40 CFR 80.1167 apply 

to [insert name of foreign RIN owner]. 

Pursuant to Clean Air Act section 113(c) and 

18 U.S.C. 1001, the penalty for furnishing 

false, incomplete or misleading information 

in this certification or submission is a fine of 

up to $10,000 U.S., and/or imprisonment for 

up to five years. 

[FR Doc. E7–7140 Filed 4–30–07; 8:45 am] 

BILLING CODE 6560–50–P 


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